##### 



Exhibit 3


MANAGEMENTS DISCUSSION AND
ANALYSIS

For the Year Ended December 31,
2003



---



##### 



Exhibit 3



MANAGEMENTS DISCUSSION AND
ANALYSIS


February 2, 2004

Managements Discussion and Analysis is the
Companys explanation of its financial performance for the
period covered by the financial statements along with an
analysis of the Companys financial position and prospects.
It should be read in conjunction with the Consolidated Financial
Statements and notes thereto and the Supplemental Information on
Oil and Gas Exploration and Production Activities. The
Consolidated Financial Statements have been prepared in
accordance with accounting principles generally accepted in
Canada. The effect of significant differences between Canadian
and United States accounting principles is disclosed in
note 20 of the Consolidated Financial Statements. The
following discussion and analysis refers primarily to 2003 as
compared with 2002, unless otherwise indicated. Refer to the
section Results of Operations for 2002 Compared with
2001 for an abridged discussion. All dollar amounts are in
millions of Canadian dollars, unless otherwise indicated. The
calculations of barrels of oil equivalent (boe) and
thousand cubic feet of gas equivalent (mcfge) are
based on a conversion rate of six thousand cubic feet of natural
gas to one barrel of crude oil. Unless otherwise indicated, all
production volumes quoted are gross, which represent the
Companys working interest share before royalties, and
prices are those realized by the Company, which include the
effect of hedging gains and losses.

Managements Discussion and Analysis
contains the term cash flow from operations, which
should not be considered an alternative to, or more meaningful
than cash flow from operating activities as
determined in accordance with generally accepted accounting
principles as an indicator of the Companys financial
performance. The Companys determination of cash flow from
operations may not be comparable to that reported by other
companies. Cash flow from operations generated by each business
segment represents a measurement of financial performance for
which each reporting business segment is responsible. The other
items required to arrive at consolidated cash flow from
operations are considered to be a corporate responsibility.

Certain of the statements set forth under
Managements Discussion and Analysis and
elsewhere in this Annual Report, including statements which may
contain words such as could, expect,
believe, will and similar expressions
and statements relating to matters that are not historical
facts, are forward-looking and are based upon the Companys
current belief as to the outcome and timing of such future
events. There are numerous risks and uncertainties that can
affect the outcome and timing of such events, including many
factors beyond the control of the Company. These factors
include, but are not limited to, the matters described under the
heading Business Environment. Should one or more of
these events occur, or should any of the underlying assumptions
prove incorrect, the Companys actual results and plans for
2004 and beyond could differ materially from those expressed in
the forward-looking statements. The Company does not undertake
to update, revise or correct any of the forward-looking
information. Such forward-looking statements should be read in
conjunction with the Companys disclosures under the
heading: CAUTIONARY STATEMENT FOR THE PURPOSES OF THE
SAFE HARBOR PROVISIONS OF THE PRIVATE SECURITIES
LITIGATION REFORM ACT OF 1995. Refer to the section
Forward-looking Statements.

OVERVIEW

Summary of Results

Huskys operations are organized into three
major business segments:



| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                            
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | The upstream segment includes the exploration for
    and the development and production of crude oil and natural gas
    in Western Canada, offshore the Canadian East Coast and offshore
    China and other international areas.                                                                                                                                                                                                                        
|
| |  | The midstream segment is organized into two
    reportable business segments; heavy crude oil upgrading
    operations, and infrastructure and commodity marketing
    operations. The infrastructure and commodity marketing segment
    comprises heavy crude oil pipeline and processing operations,
    natural gas storage, cogeneration operations, and marketing of
    crude oil, natural gas, natural gas liquids, sulphur and
    petroleum coke.
|
| |  | The refined products segment includes the
    refining of crude oil and the marketing of refined petroleum
    products including asphalt products.                                                                                                                                                                                                                                                                                                        

1



---



##### 



Segmented Financial Summary

|                                                 |                            |                                      |       |        |  |      |     |        |   |      |       |      |   |  |    |     |   |   |       |      |  
|------------------------------------------------ | -------------------------- | ------------------------------------ | ----- | ------ |  | ---- | --- | ------ | - | ---- | ----- | ---- | - |  | -- | --- | - | - | ----- | ---- | -
|                                                 |                            |                                     
|                                                 |                            | Year ended December 31              
|                                                 |                            |                                     
|                                                 |                            |                                      |       | %      |  |      |     | %      |   |     
|                                                 |                            | 2003                                 |       | Change |  | 2002 |     | Change |   | 2001
|                                                 |                            |                                      |       |        |  |      |     |        |   |     
|                                                 |                            |                                     
|                                                 |                            | ($ millions, except where indicated)
|Sales and operating revenues, net of royalties   |                            | $                                    | 7,658 |        |  |      | 20  |        |   | $    | 6,384 |      |   |  | (3 | )   |   | $ | 6,596 |     
|Cash flow from operations                        |                            |                                      | 2,459 |        |  |      | 17  |        |   |      | 2,096 |      |   |  | 8  |     |   |   | 1,946 |     
|Segmented earnings                               |                            |                                      |       |        |  |      |     |        |   |      |       |      |   |  |    |     |   |   |       |     
|                                                 | Upstream                   |                                      | $     | 1,048  |  |      |     | 52     |   |      | $     | 688  |   |  |    | 43  |   |   | $     | 482  |  
|                                                 | Midstream                  |                                      |       | 185    |  |      |     | 15     |   |      |       | 161  |   |  |    | (37 | ) |   |       | 256  |  
|                                                 | Refined Products           |                                      |       | 28     |  |      |     | (13    | ) |      |       | 32   |   |  |    | (49 | ) |   |       | 63   |  
|                                                 | Corporate and eliminations |                                      |       | 60     |  |      |     | 178    |   |      |       | (77  | ) |  |    | 48  |   |   |       | (147 | )
|                                                 |                            |                                      |       |        |  |      |     |        |   |      |       |      |   |  |    |     |   |   |       |     
|Net earnings                                     |                            | $                                    | 1,321 |        |  |      | 64  |        |   | $    | 804   |      |   |  | 23 |     |   | $ | 654   |     
|                                                 |                            |                                      |       |        |  |      |     |        |   |      |       |      |   |  |    |     |   |   |       |     
|                                                 | Per share  Basic          |                                      | $     | 3.23   |  |      |     | 72     |   |      | $     | 1.88 |   |  |    | 26  |   |   | $     | 1.49 |  
| Diluted                                        |                            |                                      | 3.22  |        |  |      | 71  |        |   |      | 1.88  |      |   |  | 27 |     |   |   | 1.48  |     
|Dividends declared per share                     |                            |                                      | 1.38  |        |  |      | 283 |        |   |      | 0.36  |      |   |  |   |     |   |   | 0.36  |     
|Return on equity (percent)                       |                            |                                      | 24.0  |        |  |      |     |        |   |      | 16.7  |      |   |  |    |     |   |   | 15.4  |     
|Return on average capital employed
    (percent) |                            |                                      | 18.0  |        |  |      |     |        |   |      | 12.2  |      |   |  |    |     |   |   | 10.9  |     

Business Environment

Huskys financial results are significantly
influenced by its business environment. Risks include, but are
not limited to:



| |   |                                                                         
| | - | ------------------------------------------------------------------------
| |  | Crude oil and natural gas prices                                        
|
| |  | Cost to find, develop, produce and deliver crude
    oil and natural gas
|
| |  | Demand for and ability to deliver natural gas                           
|
| |  | The exchange rate between the Canadian and
    U.S. dollars             
|
| |  | Refined products margins                                                
|
| |  | Demand for Huskys pipeline capacity                                    
|
| |  | Demand for refined petroleum products                                   
|
| |  | Government regulations                                                  
|
| |  | Cost of capital                                                         

Average Benchmark Prices and
U.S. Exchange Rate

|                                      |  |  |                 |      |  |      |       |      |  |   |       |  |  |   |       | 
|------------------------------------- |  |  | --------------- | ---- |  | ---- | ----- | ---- |  | - | ----- |  |  | - | ----- | 
|                                      |  |  |                 | 2003 |  | 2002 |       | 2001
|                                      |  |  |                 |      |  |      |       |     
|West Texas Intermediate (WTI) (1)   |  |  | (U.S.  $/bbl)   |      |  | $    | 31.04 |      |  | $ | 26.08 |  |  | $ | 25.97 | 
|Canadian par light crude 0.3% sulphur |  |  | ($/bbl)         |      |  | $    | 43.56 |      |  | $ | 40.28 |  |  | $ | 39.39 | 
|NYMEX natural gas (1)                 |  |  | (U.S.  $/mmbtu) |      |  | $    | 5.39  |      |  | $ | 3.25  |  |  | $ | 4.38  | 
|NIT natural gas                       |  |  | ($/GJ)          |      |  | $    | 6.35  |      |  | $ | 3.86  |  |  | $ | 5.97  | 
|WTI/Lloyd blend differential          |  |  | (U.S.  $/bbl)   |      |  | $    | 8.55  |      |  | $ | 6.47  |  |  | $ | 10.74 | 
|U.S./Canadian dollar exchange rate    |  |  | (U.S. $)        |      |  | $    | 0.716 |      |  | $ | 0.637 |  |  | $ | 0.646 | 






|    |                                                                                       
|--- | --------------------------------------------------------------------------------------
|(1) | Prices quoted are near-month contract prices for
    settlement during the next month.



| |                     
| | --------------------
| | Commodity Price Risk

Huskys earnings depend largely on the
profitability of its upstream business, which is significantly
affected by fluctuations in oil and gas prices. Commodity prices
have been, and are expected to continue to be, volatile due to a
number of factors beyond Huskys control. Refer to the
section Financial and Derivative Instruments for a
discussion of the Companys use of hedging contracts.

2



---



##### 



Crude Oil

The prices received for the crude oil and NGL
sold by Husky are related to the price of crude oil in world
markets. Prices for heavy crude oil and other lesser quality
crudes trade at a discount or differential to light crude oil.
These prices are further affected by the use of hedging
contracts, which provide for payments or receipts depending on
whether the underlying commodity price is higher or lower than
an agreed upon strike price.

Benchmark crude oil prices averaged higher in
2003 compared with 2002. The price for West Texas Intermediate
(WTI) crude oil averaged U.S. $32.70/bbl in
January 2003 and fluctuated between monthly averages of
U.S. $35.73/bbl and U.S. $28.07/bbl during the
remainder of the year.

During 2003 buoyant world crude oil prices
resulted from production quotas set by the Organization of
Petroleum Exporting Countries (OPEC), Nigerian and
Venezuelan production restrictions and the war in Iraq. Iraqi
production averaged approximately 350,000 bbls/day from April
through July 2003. In August Iraqi production recovered
considerably and averaged 1,400,000 bbls/day from August through
October 2003 or approximately 70 percent of normal pre-war
levels. OPEC has maintained a greater degree of production
discipline over the past three years with the intention of
maintaining prices within a U.S. $22/bbl 
U.S. $28/bbl price range. Toward the end of 2003, OPEC
announced cuts to its production quotas that were intended to
keep prices within the price band. Numerous factors could affect
world crude oil prices in the remainder of 2004. Early January
2004 commercial crude oil inventories were significantly lower
than the five-year average. Low crude oil inventories restrict
the refiners ability to increase distillate production,
should protracted cold weather increase heating demand.

During 2003 heavy crude oil differentials
averaged U.S. $8.55/bbl for WTI/Lloyd blend compared with
U.S. $6.47/bbl during 2002. The wider differential tends to
reduce Huskys overall financial results as the
Companys crude oil production is weighted toward heavier
gravity crudes. In periods of wider differentials, Huskys
heavy oil upgrader offsets in part the impact of lower heavy
crude prices.

WTI and Husky Realized Crude Oil
Prices

(LINE GRAPH)

Natural Gas

The price of natural gas in North America is
affected by regional supply and demand factors, particularly
those affecting the United States such as weather conditions,
pipeline delivery capacity, the availability of alternative
sources of less costly energy supply, inventory levels and
general industry activity levels. Periodic imbalances between
supply and demand for natural gas are common and result in
volatile pricing. The price of natural gas, unlike crude oil, is
not subject to the influence of an organization such as OPEC.

Throughout the last five months of 2003 natural
gas prices on the New York Mercantile Exchange
(NYMEX) drifted lower, averaging just over
U.S. $5/mmbtu. With the arrival of colder weather at the
end of November, prices on the NYMEX began to increase and the
near-month price on December 31, 2003 for February 2004
delivery was U.S. $6.19/mmbtu. At the beginning of January
2004 natural gas storage in the U.S. was just above the
five-year average.

3



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##### 



The selling price for Huskys natural gas is
based either on fixed price contracts, spot prices, NYMEX or
other regional market prices. The prices received are further
affected by the Companys hedging contracts, which provide
for payments or receipts depending on whether the underlying
commodity price is higher or lower than an agreed upon strike
price. Refer to Financial and Derivative Instruments
for a discussion of the Companys use of hedging contracts.

NYMEX Natural Gas and Husky Realized Natural
Gas Prices

(LINE GRAPH)

Upgrading Differential

The profitability of Huskys heavy oil
upgrading operations is dependent upon the amount by which
revenues from the synthetic crude oil produced exceed the costs
of the heavy oil feedstock plus the related operating costs. An
increase in the price of blended heavy crude oil feedstock which
is not accompanied by an equivalent increase in the price of
synthetic crude oil would reduce the profitability of
Huskys upgrading operations. Husky has significant crude
oil production that trades at a discount to light crude oil, and
any negative effect of a narrower differential on upgrading
operations would be more than offset by a positive effect on
revenues in the upstream segment from heavy oil production.

Refined Products Margins

The margins realized by Husky for refined
products are affected by crude oil price fluctuations, which
affect refinery feedstock costs, and third-party light oil
refined product purchases. Huskys ability to maintain
refined products margins in an environment of higher feedstock
costs is contingent upon its ability to pass on higher costs to
its customers.

Integration

Huskys production of light, medium and
heavy crude oil and natural gas and the efficient operation of
its upgrader, refineries and other infrastructure provide
opportunities to take advantage of any increases in commodity
prices while assisting in managing commodity price volatility.
Although predominantly an oil and gas producer, Huskys
integrated organization is such that the upstream business
segments output provides input to the midstream and
refined products segments.

Foreign Exchange Risk

Huskys results are affected by the exchange
rate between the Canadian and U.S. dollars. The majority of
Huskys revenues are received in U.S. dollars or from
the sale of oil and gas commodities that receive prices
determined by reference to U.S. benchmark prices. A
decrease in the value of the Canadian dollar relative to the
U.S. dollar will increase the revenues received from the
sale of oil and gas commodities and correspondingly an increase
in the value of the Canadian dollar relative to the
U.S. dollar will decrease the revenues received from the
sale of oil and gas commodities. The majority of Huskys
expenditures are in Canadian dollars. In addition, a change in
the value of the Canadian dollar against the U.S. dollar
will result in an increase or decrease in Huskys
U.S. dollar denominated debt,

4



---



##### 



as expressed in Canadian dollars, as well as in
the related interest expense. At December 31, 2003,
74 percent or $1.5 billion of Huskys long-term
debt and capital securities was denominated in
U.S. dollars. The Cdn./U.S. exchange rate at the end
of 2003 was $1.29. The percentage of Huskys long-term debt
exposed to the Cdn./U.S. exchange rate decreases to
54 percent when the cross currency swaps are included.
Refer to Financial and Derivative Instruments.


Interest Rates

The Company maintains a portion of its debt in
floating rate facilities which are exposed to interest rate
fluctuations. The Company will occasionally fix its floating
rate debt or create a variable rate for its fixed rate debt
using derivative financial instruments. Refer to Financial
and Derivative Instruments.

Environmental Regulation

Most aspects of Huskys business are subject
to environmental laws and regulations. Similar to other
companies in the oil and gas industry, Husky incurs costs for
preventive and corrective actions. Changes to regulations could
have an adverse effect on Huskys results of operations and
financial condition.

International Operations

Huskys international operations may be
affected by a variety of factors including political and
economic developments, exchange controls, currency fluctuations,
royalty and tax increases, import and export regulations and
other foreign laws or policies affecting foreign trade or
investment.

Sensitivity Analysis

The following table is indicative of the relative
effect on net earnings and cash flow of changes in certain key
variables. The analysis is based on business conditions and
production volumes during 2003. Each separate item in the
sensitivity analysis shows the effect of an increase in that
variable only; all other variables are held constant. While
these sensitivities are applicable for the period and magnitude
of changes on which they are based, they may not be applicable
in other periods, under other economic circumstances or greater
magnitudes of change.

Sensitivity Analysis

|                                          |                  |          |                   |                   |  |               |     |              |   |               |       |       |   |  |     |     |   |  |       |       |  
|----------------------------------------- | ---------------- | -------- | ----------------- | ----------------- |  | ------------- | --- | ------------ | - | ------------- | ----- | ----- | - |  | --- | --- | - |  | ----- | ----- | -
|                                          |                  |          |                   |                   |  |              
|                                          |                  |          |                   | Effect on Pre-tax |  | Effect on    
|Item                                      |                  | Increase |                   | Cash Flow         |  | Net Earnings 
|                                          |                  |          |                   |                   |  |              
|                                          |                  |          |                   |                   |  |               |     |             
|                                          |                  |          |                   | ($ millions)      |  | ($/share) (4) |     | ($ millions) |   | ($/share) (4)
|WTI benchmark crude oil price             |                  |          |                   |                   |  |               |     |              |   |               |       |       |   |  |     |     |   |  |       |      
|                                          | Excluding hedges |          |                   | U.S. $1.00/bbl    |  |               |     | 93           |   |               |       | 0.22  |   |  |     | 63  |   |  |       | 0.15  |  
|                                          | Including hedges |          |                   | U.S. $1.00/bbl    |  |               |     | 54           |   |               |       | 0.13  |   |  |     | 34  |   |  |       | 0.08  |  
|NYMEX benchmark natural gas price (1)     |                  |          |                   |                   |  |               |     |              |   |               |       |       |   |  |     |     |   |  |       |      
|                                          | Excluding hedges |          |                   | U.S.  $0.20/mmbtu |  |               |     | 34           |   |               |       | 0.08  |   |  |     | 21  |   |  |       | 0.05  |  
|                                          | Including hedges |          |                   | U.S.  $0.20/mmbtu |  |               |     | 18           |   |               |       | 0.04  |   |  |     | 10  |   |  |       | 0.02  |  
|Light/ heavy crude oil differential (2)   |                  |          | Cdn. $1.00/bbl    |                   |  |               | (25 | )            |   |               | (0.06 | )     |   |  | (16 | )   |   |  | (0.04 | )    
|Light oil margins                         |                  |          | Cdn. $0.005/litre |                   |  |               | 15  |              |   |               | 0.04  |       |   |  | 9   |     |   |  | 0.02  |      
|Asphalt margins                           |                  |          | Cdn. $1.00/bbl    |                   |  |               | 8   |              |   |               | 0.02  |       |   |  | 5   |     |   |  | 0.01  |      
|Exchange rate (U.S. $ per
    Cdn. $) (3) |                  |          |                   |                   |  |               |     |              |   |               |       |       |   |  |     |     |   |  |       |      
|                                          | Including hedges |          |                   | U.S. $0.01        |  |               |     | (50          | ) |               |       | (0.12 | ) |  |     | (34 | ) |  |       | (0.08 | )






|    |                                                                                                                                                                                                                                                                                                                     
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Includes decrease in earnings related to natural
    gas consumption.                                                                                                                                                                                                                                               
|   
|(2) | Includes impact of upstream and upgrading
    operations only.                                                                                                                                                                                                                                                      
|   
|(3) | Assumes no foreign exchange gains or losses on
    U.S. dollar denominated long-term debt and other monetary
    items. The impact of the Canadian dollar strengthening by
    U.S. $0.01 would be an increase of $8 million in net
    earnings based on December 31, 2003 U.S. dollar
    denominated debt levels.
|   
|(4) | Based on December 31, 2003 common shares
    outstanding of 422 million.                                                                                                                                                                                                                                            

Huskys Business Plan

Husky will continue to execute its long-term
business plan, which is expected to increase reserves and
production in the upstream business segment through selective
acquisitions and effective exploration and development programs.

5



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##### 



Husky will also continue to enhance growth and
returns through expansion, upgrading and optimization of the
midstream and refined products businesses.


The light and medium gravity crude oil potential
of the Western Canada Sedimentary Basin, although considerable,
is generally believed to be composed of smaller accumulations.
Husky plans to optimize production from its properties in the
Western Canada Sedimentary Basin through programs to improve
recovery and through acquisitions and dispositions. Husky
benefits from having a significant position in several key
producing areas in Western Canada. Husky is the operator of the
majority of its operations and has extensive infrastructure,
which affords opportunities for cost control and economies of
scale.

Husky plans to more than offset production
declines from light and medium crude oil properties in the
Western Canada Sedimentary Basin by further exploitation of
heavy oil in the Lloydminster area of Alberta and Saskatchewan,
development of oil sands properties in Alberta, production from
the White Rose offshore project and production from projects
offshore China. In addition, 2004 plans include an oil
exploration program in an area new to Husky in the central
Mackenzie region of the Northwest Territories.

The natural gas potential of the Western Canada
Sedimentary Basin is considered to be favourable both for
shallow gas on the undisturbed plains and larger deep
accumulations in the Deep Basin and foothills overthrust areas.
Huskys natural gas production is expected to increase as a
result of exploration concentrated in these areas west of the
fifth meridian in Alberta and British Columbia and natural gas
development activity throughout the Basin, as well as through
selective acquisitions and asset rationalization.

In 2004 Husky intends to invest $2.1 billion
in capital programs. Capital totalling $1.15 billion is
planned to be spent on upstream programs located throughout the
Western Canada Sedimentary Basin, $585 million on programs
offshore the East Coast of Canada and $65 million on
international programs primarily offshore China. Capital
programs in the midstream segment will total $100 million
primarily for further debottlenecking of the Lloydminster
Upgrader and $150 million in the refined products segment
primarily for further upgrading of the marketing outlet system
and construction of an ethanol production facility. Husky plans
to invest $30 million in corporate areas in 2004.

Huskys 2004 business plan assumes that:



| |   |                                                                                                                                                                                                                                                                              
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | WTI will average U.S. $26.50/bbl and the
    WTI/Lloyd blend differential will average U.S. $6.96/bbl                                                                                                                                                                        
|
| |  | NYMEX natural gas price will average
    U.S. $5.25/mcf                                                                                                                                                                                                                      
|
| |  | the Canadian dollar will average U.S. $0.73                                                                                                                                                                                                                                  
|
| |  | U.S. $LIBOR will average 2.50 percent                                                                                                                                                                                                                                        
|
| |  | Huskys total production will average 320 to
    350 mboe/day. Production in 2004 comprises 67 to
    76 mbbls/day of light crude oil and NGL, 35 to
    40 mbbls/day of medium crude oil, 105 to 115 mbbls/day
    of heavy crude oil and 670 to 710 mmcf/day of natural gas

Husky uses derivative financial instruments when
deemed appropriate to hedge exposure to changes in the price of
crude oil and natural gas and fluctuations in interest rates and
foreign currency exchange rates. Husky does not engage in
transactions involving derivative financial instruments for
trading or speculative purposes.

During 2003 Husky entered into contractual
arrangements whereby between approximately 25 percent and
27 percent of 2004 planned annual production has been
hedged. Crude oil production totalling 31 mmbbls has been hedged
at an average price of U.S. $27.46/bbl throughout 2004 and
4.8 bcf of natural gas production has been hedged at an average
price of U.S. $6.65/mmbtu from February to April 2004. This
will protect cash flow and earnings in 2004 and facilitate the
execution of 2004 capital programs. In addition, Husky has
hedged a portion of its power purchases. From January to
December 2004, 329,400 MWh have been hedged at an average
price of $46.72/MWh.

6



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##### 



RESULTS OF OPERATIONS

Upstream



| |                        
| | -----------------------
| | 2003 Compared with 2002

Huskys earnings from the upstream segment
increased by $360 million (52 percent) to
$1,048 million in 2003 from $688 million in 2002.

Upstream Earnings Summary

|                                      |  |                        |       |      |  |      |       |   |  |   |       | 
|------------------------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|                                      |  |                       
|                                      |  | Year ended December 31
|                                      |  |                       
|                                      |  | 2003                   |       | 2002 |  | 2001
|                                      |  |                        |       |      |  |     
|                                      |  |                       
|                                      |  | ($ millions)          
|Gross revenues                        |  | $                      | 3,796 |      |  | $    | 3,120 |   |  | $ | 2,667 | 
|Royalties                             |  |                        | 584   |      |  |      | 460   |   |  |   | 502   | 
|Hedging (gain)/loss                   |  |                        | 26    |      |  |      | (5    | ) |  |   |      | 
|                                      |  |                        |       |      |  |      |       |   |  |   |       | 
|Net revenues                          |  |                        | 3,186 |      |  |      | 2,665 |   |  |   | 2,165 | 
|Operating and administrative expenses |  |                        | 855   |      |  |      | 729   |   |  |   | 648   | 
|DD&A                                  |  |                        | 958   |      |  |      | 851   |   |  |   | 728   | 
|Income taxes                          |  |                        | 325   |      |  |      | 397   |   |  |   | 307   | 
|                                      |  |                        |       |      |  |      |       |   |  |   |       | 
|Earnings                              |  | $                      | 1,048 |      |  | $    | 688   |   |  | $ | 482   | 
|                                      |  |                        |       |      |  |      |       |   |  |   |       | 

Huskys total revenues from upstream
operations were $3,796 million in 2003 compared with
$3,120 million in 2002 primarily due to:



| |   |                                                                      
| | - | ---------------------------------------------------------------------
| |  | higher price realization for crude oil and
    natural gas           
|
| |  | higher sales volumes of light and heavy crude oil
    and natural gas

the effect of which was partially offset by:



| |   |                                       
| | - | --------------------------------------
| |  | lower sales volume of medium crude oil
|
| |  | higher unit operating costs           

Higher production volumes of heavy crude oil were
primarily due to:



| |   |                                                                                                                                                   
| | - | --------------------------------------------------------------------------------------------------------------------------------------------------
| |  | the ongoing Lloydminster heavy oil development
    programs and progress at the Bolney/ Celtic steam assisted
    gravity drainage thermal project

Operating costs per unit of production increased
11 percent in 2003 compared with 2002 primarily as a result
of:



| |   |                                                                                                                                                      
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------
| |  | higher energy costs                                                                                                                                  
|
| |  | higher operating and maintenance costs for light/
    medium crude oil properties under secondary and tertiary
    recovery schemes in Western Canada
|
| |  | higher operating and maintenance costs for the
    extensive facilities associated with shallow gas production in
    Western Canada                 

partially offset by:



| |   |                                                          
| | - | ---------------------------------------------------------
| |  | lower unit operating costs at Terra Nova and
    Wenchang

Depletion, depreciation and amortization
(DD&A) increased to $8.40/boe in 2003 from
$7.76/boe in 2002 and primarily resulted from:



| |   |                                                                                                                                        
| | - | ---------------------------------------------------------------------------------------------------------------------------------------
| |  | higher maintenance capital requirements for
    properties under secondary and tertiary recovery and shallow
    natural gas operations
|
| |  | offshore operations that require substantial
    infrastructure capital                                                                
|
| |  | acquired oil and gas properties which, in
    accordance with the purchase method of accounting, are recorded
    at fair value        

Income taxes with respect to the upstream
business segment decreased in 2003 to $325 million from
$397 million in 2002 despite higher pre-tax earnings.
Income taxes in 2003 were partially offset by a number of
non-recurring

7



---



##### 



benefits. On June 13, 2003, Bill C-48
received first reading in the House of Commons and thus was
considered to be substantively enacted. This amendment to the
Income Tax Act reduces the income tax rate on resource income by
seven percent, provides for the deduction from income of crown
royalties and eliminates the resource allowance deduction. The
amendment will be phased in over a five-year period. The total
benefit recorded with respect to Bill C-48 was
$141 million. In addition, a non-recurring upstream benefit
totalling $18 million was recorded pursuant to
Bill 41, the Alberta Corporate Tax Amendment Act, 2003.
Both benefits reduced future income taxes related to upstream
operations.


During 2002, a non-recurring benefit of
$23 million was recorded with respect to Alberta and
British Columbia income tax rate reductions.

Net Revenue Variance Analysis

|                             |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |      |  
|---------------------------- | -------------- | ------------ | ----- | ------- | - | ----- | ----- | ----- | - | - | -- | -- |  | - | ----- | ---- | -
|                             |                | Crude Oil    |       | Natural |   |       |       |      
|                             |                | & NGL        |       | Gas     |   | Other |       | Total
|                             |                |              |       |         |   |       |       |      
|                             |                |             
|                             |                | ($ millions)
|Year ended December 31, 2001 |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     
|Net revenues                 |                | $            | 1,262 |         |   | $     | 873   |       |   | $ | 30 |    |  | $ | 2,165 |     
|                             | Price changes  |              |       | 573     |   |       |       | (342  | ) |   |    | 8  |  |   |       | 239  |  
|                             | Volume changes |              |       | 218     |   |       |       | (7    | ) |   |    |   |  |   |       | 211  |  
|                             | Royalties      |              |       | (71     | ) |       |       | 113   |   |   |    |   |  |   |       | 42   |  
|                             | Hedging        |              |       | 5       |   |       |       |      |   |   |    |   |  |   |       | 5    |  
|                             | Processing     |              |       |        |   |       |       |      |   |   |    | 3  |  |   |       | 3    |  
|                             |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     
|Year ended December 31, 2002 |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     
|Net revenues                 |                |              | 1,987 |         |   |       | 637   |       |   |   | 41 |    |  |   | 2,665 |     
|                             | Price changes  |              |       | 85      |   |       |       | 450   |   |   |    |   |  |   |       | 535  |  
|                             | Volume changes |              |       | 59      |   |       |       | 58    |   |   |    |   |  |   |       | 117  |  
|                             | Royalties      |              |       | 16      |   |       |       | (140  | ) |   |    |   |  |   |       | (124 | )
|                             | Hedging        |              |       | (50     | ) |       |       | 19    |   |   |    |   |  |   |       | (31  | )
|                             | Processing     |              |       |        |   |       |       |      |   |   |    | 24 |  |   |       | 24   |  
|Year ended December 31, 2003 |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     
|                             |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     
|Net revenues                 |                | $            | 2,097 |         |   | $     | 1,024 |       |   | $ | 65 |    |  | $ | 3,186 |     
|                             |                |              |       |         |   |       |       |       |   |   |    |    |  |   |       |     

Daily Production, before Royalties

|                                |  |  |             |                        |  |      |       |      |  |  |       |  |  |  |       | 
|------------------------------- |  |  | ----------- | ---------------------- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ----- | 
|                                |  |  |             |                       
|                                |  |  |             | Year ended December 31
|                                |  |  |             |                       
|                                |  |  |             | 2003                   |  | 2002 |       | 2001
|                                |  |  |             |                        |  |      |       |     
|Light crude oil & NGL           |  |  | (mbbls/day) |                        |  |      | 71.6  |      |  |  | 65.4  |  |  |  | 46.4  | 
|Medium crude oil                |  |  | (mbbls/day) |                        |  |      | 39.2  |      |  |  | 44.8  |  |  |  | 47.2  | 
|Heavy crude oil                 |  |  | (mbbls/day) |                        |  |      | 99.9  |      |  |  | 95.1  |  |  |  | 83.8  | 
|Natural gas                     |  |  | (mmcf/day)  |                        |  |      | 610.6 |      |  |  | 569.2 |  |  |  | 572.6 | 
|Barrels of oil equivalent (6:1) |  |  | (mboe/day)  |                        |  |      | 312.5 |      |  |  | 300.2 |  |  |  | 272.8 | 

8



---



##### 



Average Realized Prices

|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|------------------------------------ |  |  | ------- | ---------------------- |  | ---- | ----- | ---- |  | - | ----- | - |  | - | ----- | 
|                                     |  |  |         |                       
|                                     |  |  |         | Year ended December 31
|                                     |  |  |         |                       
|                                     |  |  |         | 2003                   |  | 2002 |       | 2001
|                                     |  |  |         |                        |  |      |       |     
|Light crude oil & NGL                |  |  | ($/bbl) |                        |  | $    | 39.53 |      |  | $ | 36.17 |   |  | $ | 33.15 | 
|Hedging (gain)/loss                  |  |  |         |                        |  |      | 0.80  |      |  |   | (0.09 | ) |  |   |      | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Light crude oil & NGL price realized |  |  |         |                        |  | $    | 38.73 |      |  | $ | 36.26 |   |  | $ | 33.15 | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Medium crude oil                     |  |  | ($/bbl) |                        |  | $    | 31.42 |      |  | $ | 30.16 |   |  | $ | 23.69 | 
|Hedging (gain)/loss                  |  |  |         |                        |  |      | 1.85  |      |  |   | (0.19 | ) |  |   |      | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Medium crude oil price realized      |  |  |         |                        |  | $    | 29.57 |      |  | $ | 30.35 |   |  | $ | 23.69 | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Heavy crude oil price realized       |  |  | ($/bbl) |                        |  | $    | 25.87 |      |  | $ | 26.60 |   |  | $ | 17.02 | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Natural gas price                    |  |  | ($/mcf) |                        |  | $    | 5.86  |      |  | $ | 3.83  |   |  | $ | 5.47  | 
|Hedging (gain)/loss                  |  |  |         |                        |  |      | (0.08 | )    |  |   |      |   |  |   |      | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 
|Natural gas price realized           |  |  |         |                        |  | $    | 5.94  |      |  | $ | 3.83  |   |  | $ | 5.47  | 
|                                     |  |  |         |                        |  |      |       |      |  |   |       |   |  |   |       | 

Upstream Revenue Mix

|                                                           |  |                        |      |      |  |      |      |  |  |  |      | 
|---------------------------------------------------------- |  | ---------------------- | ---- | ---- |  | ---- | ---- |  |  |  | ---- | 
|                                                           |  |                       
|                                                           |  | Year ended December 31
|                                                           |  |                       
|                                                           |  | 2003                   |      | 2002 |  | 2001
|                                                           |  |                        |      |      |  |     
|Percentage of upstream sales revenues, after
    royalties |  |                        |      |      |  |      |      |  |  |  |      | 
|Light crude oil & NGL                                      |  |                        | 28%  |      |  |      | 24%  |  |  |  | 14%  | 
|Medium crude oil                                           |  |                        | 11%  |      |  |      | 25%  |  |  |  | 28%  | 
|Heavy crude oil                                            |  |                        | 27%  |      |  |      | 25%  |  |  |  | 16%  | 
|Natural gas                                                |  |                        | 34%  |      |  |      | 26%  |  |  |  | 42%  | 
|                                                           |  |                        |      |      |  |      |      |  |  |  |      | 
|Total                                                      |  |                        | 100% |      |  |      | 100% |  |  |  | 100% | 
|                                                           |  |                        |      |      |  |      |      |  |  |  |      | 

Effective Royalty Rates

|                                      |  |                        |     |      |  |      |     |  |  |  |     | 
|------------------------------------- |  | ---------------------- | --- | ---- |  | ---- | --- |  |  |  | --- | 
|                                      |  |                       
|                                      |  | Year ended December 31
|                                      |  |                       
|                                      |  | 2003                   |     | 2002 |  | 2001
|                                      |  |                        |     |      |  |     
|Percentage of upstream sales revenues |  |                        |     |      |  |      |     |  |  |  |     | 
|Light crude oil & NGL                 |  |                        | 12% |      |  |      | 13% |  |  |  | 21% | 
|Medium crude oil                      |  |                        | 18% |      |  |      | 17% |  |  |  | 18% | 
|Heavy crude oil                       |  |                        | 11% |      |  |      | 11% |  |  |  | 9%  | 
|Natural gas                           |  |                        | 21% |      |  |      | 18% |  |  |  | 23% | 
|Total                                 |  |                        | 16% |      |  |      | 15% |  |  |  | 19% | 

Operating Netbacks

Western Canada

Light Crude Oil
Netbacks(1)

|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per boe)             
|Sales revenues      |  | $                      | 39.91 |      |  | $    | 33.66 |   |  | $ | 34.25 | 
|Royalties           |  |                        | 7.28  |      |  |      | 4.55  |   |  |   | 5.76  | 
|Hedging (gain)/loss |  |                        | 0.56  |      |  |      | (0.17 | ) |  |   |      | 
|Operating costs     |  |                        | 9.27  |      |  |      | 10.46 |   |  |   | 8.15  | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|Netback             |  | $                      | 22.80 |      |  | $    | 18.82 |   |  | $ | 20.34 | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 

9



---



##### 



Medium Crude Oil
Netbacks(1)

|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per boe)             
|Sales revenues      |  | $                      | 31.57 |      |  | $    | 29.92 |   |  | $ | 23.86 | 
|Royalties           |  |                        | 5.28  |      |  |      | 5.59  |   |  |   | 4.39  | 
|Hedging (gain)/loss |  |                        | 1.79  |      |  |      | (0.19 | ) |  |   |      | 
|Operating costs     |  |                        | 9.53  |      |  |      | 7.19  |   |  |   | 7.18  | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|Netback             |  | $                      | 14.97 |      |  | $    | 17.33 |   |  | $ | 12.29 | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 

Heavy Crude Oil
Netbacks(1)

|                |  |                        |       |      |  |      |       |  |  |   |       | 
|--------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                |  |                       
|                |  | Year ended December 31
|                |  |                       
|                |  | 2003                   |       | 2002 |  | 2001
|                |  |                        |       |      |  |     
|                |  |                       
|                |  | (per boe)             
|Sales revenues  |  | $                      | 25.98 |      |  | $    | 26.48 |  |  | $ | 17.20 | 
|Royalties       |  |                        | 2.76  |      |  |      | 3.45  |  |  |   | 1.93  | 
|Operating costs |  |                        | 9.09  |      |  |      | 7.18  |  |  |   | 7.40  | 
|                |  |                        |       |      |  |      |       |  |  |   |       | 
|Netback         |  | $                      | 14.13 |      |  | $    | 15.85 |  |  | $ | 7.87  | 
|                |  |                        |       |      |  |      |       |  |  |   |       | 

Natural Gas
Netbacks(2)

|                    |  |                        |       |      |  |      |      |  |  |   |      | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ---- |  |  | - | ---- | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per mcfge)           
|Sales revenues      |  | $                      | 5.79  |      |  | $    | 3.97 |  |  | $ | 5.39 | 
|Royalties           |  |                        | 1.29  |      |  |      | 0.81 |  |  |   | 1.30 | 
|Hedging (gain)/loss |  |                        | (0.08 | )    |  |      |     |  |  |   |     | 
|Operating costs     |  |                        | 0.79  |      |  |      | 0.70 |  |  |   | 0.58 | 
|                    |  |                        |       |      |  |      |      |  |  |   |      | 
|Netback             |  | $                      | 3.79  |      |  | $    | 2.46 |  |  | $ | 3.51 | 
|                    |  |                        |       |      |  |      |      |  |  |   |      | 

Total Western Canada Upstream
Netbacks(1)

|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per boe)             
|Sales revenues      |  | $                      | 31.58 |      |  | $    | 27.04 |   |  | $ | 26.42 | 
|Royalties           |  |                        | 5.48  |      |  |      | 4.46  |   |  |   | 5.04  | 
|Hedging (gain)/loss |  |                        | 0.14  |      |  |      | (0.05 | ) |  |   |      | 
|Operating costs     |  |                        | 7.56  |      |  |      | 6.54  |   |  |   | 6.08  | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|Netback             |  | $                      | 18.40 |      |  | $    | 16.09 |   |  | $ | 15.30 | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 






|    |                                                        
|--- | -------------------------------------------------------
|(1) | Includes associated co-products converted to boe.      
|   
|(2) | Includes associated co-products converted to
    mcfge.

10



---



##### 



Terra Nova Crude Oil Netbacks

|                    |  |                        |       |      |  |      |       |  |  |   |   | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- |  |  | - | - | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per boe)             
|Sales revenues      |  | $                      | 38.91 |      |  | $    | 35.47 |  |  | $ |  | 
|Royalties           |  |                        | 0.81  |      |  |      | 0.36  |  |  |   |  | 
|Hedging (gain)/loss |  |                        | 1.95  |      |  |      |      |  |  |   |  | 
|Operating costs     |  |                        | 3.16  |      |  |      | 3.62  |  |  |   |  | 
|                    |  |                        |       |      |  |      |       |  |  |   |   | 
|Netback             |  | $                      | 32.99 |      |  | $    | 31.49 |  |  | $ |  | 
|                    |  |                        |       |      |  |      |       |  |  |   |   | 

Wenchang Crude Oil Netbacks

|                |  |                        |       |      |  |      |       |  |  |   |   | 
|--------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- |  |  | - | - | 
|                |  |                       
|                |  | Year ended December 31
|                |  |                       
|                |  | 2003                   |       | 2002 |  | 2001
|                |  |                        |       |      |  |     
|                |  |                       
|                |  | (per boe)             
|Sales revenues  |  | $                      | 41.45 |      |  | $    | 44.36 |  |  | $ |  | 
|Royalties       |  |                        | 3.80  |      |  |      | 2.65  |  |  |   |  | 
|Operating costs |  |                        | 1.94  |      |  |      | 2.15  |  |  |   |  | 
|                |  |                        |       |      |  |      |       |  |  |   |   | 
|Netback         |  | $                      | 35.71 |      |  | $    | 39.56 |  |  | $ |  | 
|                |  |                        |       |      |  |      |       |  |  |   |   | 

Total Upstream
Netbacks(1)

|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | - |  | - | ----- | 
|                    |  |                       
|                    |  | Year ended December 31
|                    |  |                       
|                    |  | 2003                   |       | 2002 |  | 2001
|                    |  |                        |       |      |  |     
|                    |  |                       
|                    |  | (per boe)             
|Sales revenues      |  | $                      | 32.69 |      |  | $    | 28.12 |   |  | $ | 26.42 | 
|Royalties           |  |                        | 5.11  |      |  |      | 4.20  |   |  |   | 5.04  | 
|Hedging (gain)/loss |  |                        | 0.23  |      |  |      | (0.05 | ) |  |   |      | 
|Operating costs     |  |                        | 6.92  |      |  |      | 6.24  |   |  |   | 6.08  | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 
|Netback             |  | $                      | 20.43 |      |  | $    | 17.73 |   |  | $ | 15.30 | 
|                    |  |                        |       |      |  |      |       |   |  |   |       | 






|    |                                                  
|--- | -------------------------------------------------
|(1) | Includes associated co-products converted to boe.

Midstream

2003 Compared with 2002

Total midstream earnings increased by
$24 million (15 percent) to $185 million in 2003
from $161 million in 2002.

11



---



##### 



Upgrading Earnings Summary

|                            |  |  |             |                                      |  |      |       |      |  |   |       |   |  |   |       |  
|--------------------------- |  |  | ----------- | ------------------------------------ |  | ---- | ----- | ---- |  | - | ----- | - |  | - | ----- | -
|                            |  |  |             |                                     
|                            |  |  |             | Year ended December 31              
|                            |  |  |             |                                     
|                            |  |  |             | 2003                                 |  | 2002 |       | 2001
|                            |  |  |             |                                      |  |      |       |     
|                            |  |  |             |                                     
|                            |  |  |             | ($ millions, except where indicated)
|Gross margin                |  |  |             |                                      |  | $    | 313   |      |  | $ | 246   |   |  | $ | 428   |  
|Operating costs             |  |  |             |                                      |  |      | 205   |      |  |   | 154   |   |  |   | 192   |  
|Other expenses (recoveries) |  |  |             |                                      |  |      | (4    | )    |  |   | (6    | ) |  |   | (12   | )
|DD&A                        |  |  |             |                                      |  |      | 20    |      |  |   | 18    |   |  |   | 17    |  
|Income taxes                |  |  |             |                                      |  |      | 21    |      |  |   | 26    |   |  |   | 73    |  
|                            |  |  |             |                                      |  |      |       |      |  |   |       |   |  |   |       |  
|Earnings                    |  |  |             |                                      |  | $    | 71    |      |  | $ | 54    |   |  | $ | 158   |  
|                            |  |  |             |                                      |  |      |       |      |  |   |       |   |  |   |       |  
|Upgrader throughput (1)     |  |  | (mbbls/day) |                                      |  |      | 72.5  |      |  |   | 65.4  |   |  |   | 71.7  |  
|Synthetic crude oil sales   |  |  | (mbbls/day) |                                      |  |      | 63.6  |      |  |   | 59.3  |   |  |   | 59.5  |  
|Upgrading differential      |  |  | ($/bbl)     |                                      |  | $    | 12.88 |      |  | $ | 10.81 |   |  | $ | 17.91 |  
|Unit margin                 |  |  | ($/bbl)     |                                      |  | $    | 13.51 |      |  | $ | 11.05 |   |  | $ | 19.79 |  
|Unit operating cost (2)     |  |  | ($/bbl)     |                                      |  | $    | 7.77  |      |  | $ | 6.48  |   |  | $ | 7.35  |  






|    |                                                   
|--- | --------------------------------------------------
|(1) | Throughput includes diluent returned to the field.
|   
|(2) | Based on throughput.                              

Upgrading earnings increased by 31 percent
in 2003 primarily due to:



| |   |                                                                                              
| | - | ---------------------------------------------------------------------------------------------
| |  | wider upgrading differential, which averaged
    $12.88/bbl in 2003 versus $10.81/bbl in 2002
|
| |  | higher throughput and sales volume                                                           

partially offset by:



| |   |                                                                     
| | - | --------------------------------------------------------------------
| |  | higher unit operating costs, which were primarily
    energy related

Upgrading Earnings Variance Analysis

|                             |                                      |              |     |      |  
|---------------------------- | ------------------------------------ | ------------ | --- | ---- | -
|                             |                                      | ($ millions)
|                             |                                      |             
|Year ended December 31, 2001 |                                      | $            | 158 |     
|                             | Volume                               |              |     | (1   | )
|                             | Differential                         |              |     | (181 | )
|                             | Operating costs  energy related     |              |     | 39   |  
|                             | Operating costs  non-energy related |              |     | (1   | )
|                             | Other                                |              |     | (6   | )
|                             | DD&A                                 |              |     | (1   | )
|                             | Income taxes                         |              |     | 47   |  
|                             |                                      |              |     |     
|Year ended December 31, 2002 |                                      |              | 54  |     
|                             | Volume                               |              |     | 18   |  
|                             | Differential                         |              |     | 49   |  
|                             | Operating costs  energy related     |              |     | (49  | )
|                             | Operating costs  non-energy related |              |     | (2   | )
|                             | Other                                |              |     | (2   | )
|                             | DD&A                                 |              |     | (2   | )
|                             | Income taxes                         |              |     | 5    |  
|                             |                                      |              |     |     
|Year ended December 31, 2003 |                                      | $            | 71  |     
|                             |                                      |              |     |     

12



---



##### 



Infrastructure and Marketing Earnings
Summary

|                                          |                                    |                           |     |      |  |      |     |     |  |   |     |     | 
|----------------------------------------- | ---------------------------------- | ------------------------- | --- | ---- |  | ---- | --- | --- |  | - | --- | --- | 
|                                          |                                    |                          
|                                          |                                    | Year ended December 31   
|                                          |                                    |                          
|                                          |                                    | 2003                      |     | 2002 |  | 2001
|                                          |                                    |                           |     |      |  |     
|                                          |                                    |                          
|                                          |                                    | ($ millions, except where
|                                          |                                    | indicated)               
|Gross margin                              |                                    |                           |     |      |  |      |     |     |  |   |     |    
|                                          | Pipeline                           |                           | $   | 66   |  |      | $   | 55  |  |   | $   | 86  | 
|                                          | Other infrastructure and marketing |                           |     | 141  |  |      |     | 147 |  |   |     | 111 | 
|                                          |                                    |                           |     |      |  |      |     |     |  |   |     |    
|                                          |                                    |                           | 207 |      |  |      | 202 |     |  |   | 197 |    
|Other expenses                            |                                    |                           | 8   |      |  |      | 10  |     |  |   | 10  |    
|DD&A                                      |                                    |                           | 21  |      |  |      | 20  |     |  |   | 17  |    
|Income taxes                              |                                    |                           | 64  |      |  |      | 65  |     |  |   | 72  |    
|                                          |                                    |                           |     |      |  |      |     |     |  |   |     |    
|Earnings                                  |                                    | $                         | 114 |      |  | $    | 107 |     |  | $ | 98  |    
|                                          |                                    |                           |     |      |  |      |     |     |  |   |     |    
|Aggregate pipeline throughput (mbbls/day) |                                    |                           | 484 |      |  |      | 457 |     |  |   | 537 |    
|                                          |                                    |                           |     |      |  |      |     |     |  |   |     |    

Infrastructure and marketing earnings increased
by seven percent in 2003 primarily due to:



| |   |                                           
| | - | ------------------------------------------
| |  | higher heavy crude oil pipeline throughput
|
| |  | higher cogeneration income                

partially offset by:



| |   |                                                                
| | - | ---------------------------------------------------------------
| |  | lower crude oil and natural gas commodity
    marketing margins

Refined Products

2003 Compared with 2002

Total refined products earnings decreased by
$4 million (13 percent) to $28 million in 2003
from $32 million in 2002. Light oil refined products
earnings decreased primarily due to lower fuel margins. Earnings
from asphalt products operations increased reflecting strong
margins and sales volumes.

Refined Products Earnings Summary

|                              |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |      | 
|----------------------------- | ----------------------------- |  |  | ------------------------- |  | ---- | --- | ---- |  | - | --- | ---- |  | - | --- | ---- | 
|                              |                               |  |  |                          
|                              |                               |  |  | Year ended December 31   
|                              |                               |  |  |                          
|                              |                               |  |  | 2003                      |  | 2002 |     | 2001
|                              |                               |  |  |                           |  |      |     |     
|                              |                               |  |  |                          
|                              |                               |  |  | ($ millions, except where
|                              |                               |  |  | indicated)               
|Gross margin                  |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|                              | Fuel sales                    |  |  |                           |  |      | $   | 71   |  |   | $   | 81   |  |   | $   | 69   | 
|                              | Ancillary sales               |  |  |                           |  |      |     | 28   |  |   |     | 26   |  |   |     | 27   | 
|                              | Asphalt sales                 |  |  |                           |  |      |     | 51   |  |   |     | 45   |  |   |     | 106  | 
|                              |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|                              |                               |  |  |                           |  |      | 150 |      |  |   | 152 |      |  |   | 202 |     
|Operating and other expenses  |                               |  |  |                           |  |      | 70  |      |  |   | 64  |      |  |   | 59  |     
|DD&A                          |                               |  |  |                           |  |      | 34  |      |  |   | 34  |      |  |   | 31  |     
|Income taxes                  |                               |  |  |                           |  |      | 18  |      |  |   | 22  |      |  |   | 49  |     
|                              |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|Earnings                      |                               |  |  |                           |  | $    | 28  |      |  | $ | 32  |      |  | $ | 63  |     
|                              |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|Number of fuel outlets        |                               |  |  |                           |  |      | 552 |      |  |   | 571 |      |  |   | 580 |     
|Refined products sales volume |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|                              | Light oil products            |  |  | (million litres/day)      |  |      |     | 8.2  |  |   |     | 7.7  |  |   |     | 7.6  | 
|                              | Light oil products per outlet |  |  | (thousand litres/day)     |  |      |     | 10.8 |  |   |     | 10.0 |  |   |     | 9.5  | 
|                              | Asphalt products              |  |  | (mbbls/day)               |  |      |     | 22.0 |  |   |     | 20.8 |  |   |     | 21.4 | 
|Refinery throughput           |                               |  |  |                           |  |      |     |      |  |   |     |      |  |   |     |     
|                              | Prince George refinery        |  |  | (mbbls/day)               |  |      |     | 10.3 |  |   |     | 10.1 |  |   |     | 10.2 | 
|                              | Lloydminster refinery         |  |  | (mbbls/day)               |  |      |     | 25.7 |  |   |     | 22.0 |  |   |     | 23.7 | 

13



---



##### 



Corporate

2003 Compared with 2002

Interest

Interest  net, which is total debt
charges net of interest income and capitalized interest, was
$73 million in 2003 compared with $104 million in
2002. Interest capitalized in 2003 was $52 million compared
with $26 million in 2002 reflecting the higher aggregate
capital invested in the White Rose development project in 2003.
Interest income was $6 million in 2003 compared with
$1 million in 2002. Total interest on short- and long-term
debt in 2003 was $131 million, the same as in 2002. During
2003 interest on lower debt levels was offset by the effect of
higher after swap interest rates. The impact of the interest
rate risk management activities was a reduction to interest
expense of $17 million in 2003. Huskys effective
interest rate for 2003 after the effect of interest rate swaps
was 6.32 percent compared with 5.48 percent during
2002.

Foreign Exchange

Foreign exchange gains of $215 million in
2003 comprised $315 million of gains on U.S. dollar
denominated long-term debt partially offset by $73 million
of cross currency swap losses and $27 million of foreign
exchange losses on other monetary items.

Consolidated Income Taxes

Consolidated income taxes increased in 2003 to
$474 million from $420 million in 2002 as a result of
higher pre-tax earnings. Income taxes in 2003 were partially
offset by a number of non-recurring benefits. On June 13,
2003, Bill C-48 received first reading in the House of Commons
and thus was considered to be substantively enacted. This
amendment to the Income Tax Act reduces the income tax rate on
resource income by seven percent, provides for the deduction
from income of crown royalties and eliminates the resource
allowance deduction. The amendment will be phased in over a
five-year period. The total benefit recorded was
$141 million. In addition, a non-recurring benefit
totalling $20 million was recorded pursuant to Bill 41, the
Alberta Corporate Tax Amendment Act, 2003. Both benefits reduced
future income taxes. During 2002, a non-recurring benefit of
$31 million was recorded with respect to federal, Alberta
and British Columbia income tax rate reductions.

In 2003 current income taxes totalled
$147 million and comprised $73 million with respect to
the Wenchang oil field operation, $22 million of capital
taxes and $52 million of Canadian income tax.

The following table shows the effect of
non-recurring benefits for the periods noted:

|                                            |  |              |     |      |  |   |     | 
|------------------------------------------- |  | ------------ | --- | ---- |  | - | --- | 
|                                            |  | 2003         |     | 2002
|                                            |  |              |     |     
|                                            |  |             
|                                            |  | ($ millions)
|Income taxes as reported                    |  | $            | 474 |      |  | $ | 420 | 
|Canadian federal and provincial tax changes |  |              | 161 |      |  |   | 31  | 
|                                            |  |              |     |      |  |   |     | 
|Pro forma income taxes                      |  | $            | 635 |      |  | $ | 451 | 
|                                            |  |              |     |      |  |   |     | 

At December 31, 2003 and 2002, Huskys
Canadian tax pools consisted of the following:

|                                            |  |              |       |      |  |   |       | 
|------------------------------------------- |  | ------------ | ----- | ---- |  | - | ----- | 
|                                            |  | 2003         |       | 2002
|                                            |  |              |       |     
|                                            |  |             
|                                            |  | ($ millions)
|Canadian exploration expense                |  | $            | 42    |      |  | $ | 440   | 
|Canadian development expense                |  |              | 1,103 |      |  |   | 967   | 
|Canadian oil and gas property expense       |  |              | 814   |      |  |   | 1,066 | 
|Foreign exploration and development expense |  |              | 142   |      |  |   | 172   | 
|Undepreciated capital costs                 |  |              | 2,909 |      |  |   | 2,305 | 
|Other                                       |  |              | 22    |      |  |   | 56    | 
|                                            |  |              |       |      |  |   |       | 
|                                            |  | $            | 5,032 |      |  | $ | 5,006 | 
|                                            |  |              |       |      |  |   |       | 

14



---



##### 



CAPITAL RESOURCES

Operating Activities

In 2003 cash generated by operating activities
was $2,572 million, an increase of $680 million from
the $1,892 million recorded in 2002. The higher cash from
operating activities in 2003 was primarily due to higher
commodity prices and a change in non-cash working capital.

Financing Activities

In 2003 cash used in financing activities
amounted to $800 million. The cash used was composed of the
repayment of long-term debt of $971 million, payment of the
return on capital securities of $29 million, dividends of
$580 million, including a $1.00 per share special dividend
and settlement of a cross currency swap of $32 million.
Cash provided by financing activities in 2003 comprised
$598 million issuance of long-term debt and
$71 million utilization of operating lines,
$51 million of proceeds from the exercise of stock options,
proceeds from interest rate swaps totalling $44 million and
a change of $48 million in non-cash working capital.

Huskys long-term debt balances were also
reduced by $315 million during 2003 as a result of the
narrowing of the exchange rate between Canadian and
U.S. currencies.

Investing Activities

Cash used in investing activities amounted to
$2,075 million in 2003, an increase of $486 million
from the $1,589 million in 2002. Cash invested in 2003 was
composed of capital expenditures of $1,905 million,
acquisition of Marathon Canada Limited and the Western Canadian
assets of Marathon International Petroleum Canada, Ltd.
(Marathon Canada) for $809 million partially
offset by $511 million of proceeds from asset sales,
primarily certain Marathon Canada properties. Change in non-cash
working capital and other adjustments amounted to
$128 million provided by investing activities.

Capital Expenditures

The following table shows Huskys capital
expenditures for the years ended December 31:

|                 |                              |                        |       |      |     |      |       |    |     |   |       |    |     | 
|---------------- | ---------------------------- | ---------------------- | ----- | ---- | --- | ---- | ----- | -- | --- | - | ----- | -- | --- | 
|                 |                              |                       
|                 |                              | Year ended December 31
|                 |                              |                       
|                 |                              | 2003(1)                |       | 2002 |     | 2001
|                 |                              |                        |       |      |     |     
|                 |                              |                       
|                 |                              | ($ millions)          
|Upstream         |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 | Exploration                  |                        |       |      |     |      |       |    |     |   |       |    |    
|                 |                              | Western Canada         |       | $    | 326 |      |       | $  | 304 |   |       | $  | 236 | 
|                 |                              | East Coast Canada      |       |      | 24  |      |       |    | 41  |   |       |    | 81  | 
|                 |                              | International          |       |      | 26  |      |       |    | 9   |   |       |    | 5   | 
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 |                              |                        | 376   |      |     |      | 354   |    |     |   | 322   |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 | Development                  |                        |       |      |     |      |       |    |     |   |       |    |    
|                 |                              | Western Canada         |       |      | 872 |      |       |    | 730 |   |       |    | 786 | 
|                 |                              | East Coast Canada      |       |      | 533 |      |       |    | 417 |   |       |    | 110 | 
|                 |                              | International          |       |      |    |      |       |    | 66  |   |       |    | 99  | 
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 |                              |                        | 1,405 |      |     |      | 1,213 |    |     |   | 995   |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 |                              |                        | 1,781 |      |     |      | 1,567 |    |     |   | 1,317 |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|Midstream        |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 | Upgrader                     |                        |       | 25   |     |      |       | 41 |     |   |       | 47 |    
|                 | Infrastructure and marketing |                        |       | 18   |     |      |       | 17 |     |   |       | 58 |    
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 |                              |                        | 43    |      |     |      | 58    |    |     |   | 105   |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|Refined Products |                              |                        | 58    |      |     |      | 44    |    |     |   | 29    |   
|Corporate        |                              |                        | 23    |      |     |      | 23    |    |     |   | 22    |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   
|                 |                              | $                      | 1,905 |      |     | $    | 1,692 |    |     | $ | 1,473 |   
|                 |                              |                        |       |      |     |      |       |    |     |   |       |   






|    |                                                              
|--- | -------------------------------------------------------------
|(1) | 2003 does not include the acquisition of Marathon
    Canada.

15



---



##### 





| |                              
| | -----------------------------
| | Upstream Capital Expenditures

Western Canada

During 2003 capital expenditures for exploration
and development in Western Canada totalled $1,198 million
compared with $1,034 million during 2002.

Total development spending in Western Canada
during 2003 amounted to $872 million compared with
$730 million during 2002. In 2003 development capital was
directed to the following areas:



| |   |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | Alberta northwest plains area, $183 million
    for shallow natural gas drilling, completions and installation
    of facilities in the Boyer/ Cherpeta districts.                                                                                                                                                                                                                                                                                                                                                                             
|
| |  | Lloydminster heavy oil area, $303 million
    for continued exploitation and optimization including work on
    the Bolney/ Celtic thermal project, with a year-end exit rate of
    10 mbbls/day. Lloydminster capital expenditures during 2002 and
    2001 were $273 million and $324 million, respectively.                                                                                                                                                                                                                                
|
| |  | East central and southern Alberta and southern
    Saskatchewan, $259 million primarily for in-fill drilling,
    facilities optimization, acquisitions and development of the
    Shackleton/ Lacadena natural gas project in southwestern
    Saskatchewan. By the end of 2003, 240 net wells had been drilled
    and completed in the Shackleton area. Capital expenditures in
    the east central and southern Alberta and southern Saskatchewan
    areas totalled $180 million and $193 million during
    2002 and 2001, respectively.
|
| |  | British Columbia and Alberta foothills area,
    $122 million for facilities optimization and in-fill
    drilling at major Alberta foothills natural gas properties.
    Capital expenditures in the British Columbia and Alberta
    foothills area totalled $105 million and $115 million
    during 2002 and 2001, respectively.                                                                                                                                                                                                           

Exploration expenditures on Huskys
prospects in the Western Canada Sedimentary Basin in 2003
amounted to $326 million compared with $304 million in
2002. The primary exploration targets were natural gas prospects
in the Alberta foothills as well as step-out drilling throughout
Huskys properties in the Basin. In addition,
pre-development spending during 2003 on the oil sands projects
at Sunrise and Tucker, Alberta included in exploration capital
expenditures amounted to $41 million. Capital expenditures
on the oil sands projects totalled $20 million and
$8 million during 2002 and 2001, respectively.

Western Canada Drilling

|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |     | 
|--------------- | --- | ---------------------- | ----- | ---- |  | ----- | ----- | --- |  | ----- | ----- | --- |  |  | ----- | --- |  |  | ----- | --- |  |  | ----- | --- | 
|                |     |                       
|                |     | Year ended December 31
|                |     |                       
|                |     |                        |       |      |  |      
|                |     | 2003                   |       | 2002 |  | 2001 
|                |     |                        |       |      |  |      
|                |     | Gross                  |       | Net  |  | Gross |       | Net |  | Gross |       | Net
|                |     |                        |       |      |  |       |       |     |  |       |       |    
|                |     |                       
|                |     | (wells)               
|Exploration Oil |     |                        | 12    |      |  |       | 11    |     |  |       | 21    |     |  |  | 20    |     |  |  | 78    |     |  |  | 76    |    
|                | Gas |                        |       | 147  |  |       |       | 124 |  |       |       | 139 |  |  |       | 131 |  |  |       | 102 |  |  |       | 90  | 
|                | Dry |                        |       | 22   |  |       |       | 21  |  |       |       | 15  |  |  |       | 14  |  |  |       | 36  |  |  |       | 34  | 
|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |    
|                |     |                        | 181   |      |  |       | 156   |     |  |       | 175   |     |  |  | 165   |     |  |  | 216   |     |  |  | 200   |    
|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |    
|Development Oil |     |                        | 520   |      |  |       | 490   |     |  |       | 497   |     |  |  | 453   |     |  |  | 594   |     |  |  | 542   |    
|                | Gas |                        |       | 540  |  |       |       | 518 |  |       |       | 485 |  |  |       | 453 |  |  |       | 251 |  |  |       | 221 | 
|                | Dry |                        |       | 60   |  |       |       | 57  |  |       |       | 58  |  |  |       | 55  |  |  |       | 68  |  |  |       | 63  | 
|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |    
|                |     |                        | 1,120 |      |  |       | 1,065 |     |  |       | 1,040 |     |  |  | 961   |     |  |  | 913   |     |  |  | 826   |    
|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |    
|Total           |     |                        | 1,301 |      |  |       | 1,221 |     |  |       | 1,215 |     |  |  | 1,126 |     |  |  | 1,129 |     |  |  | 1,026 |    
|                |     |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |     |  |  |       |     |  |  |       |    

East Coast Canada

Capital expenditures at Huskys White Rose
oil field development offshore Newfoundland and Labrador
amounted to $505 million in 2003 compared with
$395 million in 2002. Capital expenditures with respect to
the Terra Nova oil field amounted to $28 million in 2003
compared with $22 million in 2002.

Capital expenditures for the 2003 East Coast
exploration program amounted to $24 million.

16



---



##### 



International

Exploration spending in the South China Sea
amounted to $26 million in 2003 compared with
$9 million in 2002. Spending in 2003 was primarily related
to drilling two exploration wells and preparation for an
exploration program that involved shooting an extensive seismic
program in blocks 23-15, 39-05 and 40-30 followed by
interpretation of the data. Drilling is expected to commence in
the fourth quarter of 2004.

Midstream Capital
Expenditures

Midstream capital expenditures in 2003 of
$43 million were primarily for upgrader, pipeline and
cogeneration plant upgrades and upgrader debottlenecking
front-end engineering.

Refined Products Capital
Expenditures

Refined products capital expenditures in 2003 of
$58 million were primarily for marketing outlet
improvements and refinery maintenance.

Corporate Capital
Expenditures

Corporate capital expenditures amounted to
$23 million in 2003 and 2002 and were primarily for
computer hardware and software and office furniture and
equipment.

Oil and Gas Reserves

One of the fundamental measures of value creation
is the efficient addition of oil and gas reserves. During the
three years ended December 31, 2003, Husky replaced an
average of 105 percent of production on a boe basis,
inclusive of acquisitions and divestitures.

During 2003, additions to proved natural gas
reserves amounted to 485 bcf. Field extensions and improved
recovery at Craigend, Alberta and Muskwa and Bivouac, British
Columbia totalled 187 bcf, discoveries in the Alberta
foothills area amounted to 114 bcf and acquisitions added
184 bcf, primarily from the acquisition of Marathon Canada,
which accounted for 180 bcf. Natural gas revisions reduced
reserves by 275 bcf due to a reclassification of proved
natural gas reserves for Madura, Indonesia, water incursion at
Ricinus in the Alberta foothills area and higher shallow gas
declines at Caribou and Evergreen, Alberta. Non-core
divestitures amounted to 23 bcf.

During 2003, 57 mmbbls were added to proved
crude oil and NGL reserves. Additions to proved reserves from
discoveries and extensions totalled 36 mmbbls primarily in the
Lloydminster heavy oil area. Revisions of 9 mmbbls reflect
positive technical revisions of 14 mmbbls supported by improved
performance primarily in the Lloydminster area partially offset
by revisions of 5 mmbbls primarily due to a
reclassification of NGL reserves at Madura, Indonesia.
Acquisitions of proved reserves added 12 mmbbls, 9 mmbbls of
which was acquired with Marathon Canada. Non-core property
divestitures were 5 mmbbls in 2003.

At December 31, 2003, the present value of
future net cash flows after tax from the Companys proved
oil and gas reserves, based on prices and costs in effect at
year-end and discounted at 10 percent, was
$5.8 billion compared with $7.2 billion at the end of
2002.

McDaniel & Associates Consultants Ltd., an
independent firm of oil and gas reserves evaluation engineers,
was engaged to conduct an audit of Huskys crude oil,
natural gas and natural gas products reserves. McDaniel &
Associates Consultants Ltd. issued an audit opinion stating that
Huskys internally generated proved and probable reserves
and net present values are, in aggregate, reasonable, and have
been prepared in accordance with generally accepted oil and gas
engineering and evaluation practices in the United States and as
set out in the Canadian Oil and Gas Evaluation Handbook.

17



---



##### 



Summary of Reserves

Light Crude Oil & NGL Reserves

|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------ |  | ---------------------- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                   |  |                       
|                   |  | Year ended December 31
|                   |  |                       
|                   |  |                        |     |      |  |      
|                   |  | 2003                   |     | 2002 |  | 2001 
|                   |  |                        |     |      |  |      
|                   |  | Gross                  |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                   |  |                        |     |      |  |       |     |     |  |       |     |    
|                   |  |                       
|                   |  | (mmbbls)              
|Proved developed   |  |                        | 200 |      |  |       | 177 |     |  |       | 193 |     |  |  | 171 |  |  |  | 175 |  |  |  | 153 | 
|Proved undeveloped |  |                        | 23  |      |  |       | 18  |     |  |       | 42  |     |  |  | 32  |  |  |  | 65  |  |  |  | 58  | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved       |  |                        | 223 |      |  |       | 195 |     |  |       | 235 |     |  |  | 203 |  |  |  | 240 |  |  |  | 211 | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

Medium Crude Oil Reserves

|                   |  |                        |    |      |  |       |    |     |  |       |     |     |  |  |    |  |  |  |     |  |  |  |     | 
|------------------ |  | ---------------------- | -- | ---- |  | ----- | -- | --- |  | ----- | --- | --- |  |  | -- |  |  |  | --- |  |  |  | --- | 
|                   |  |                       
|                   |  | Year ended December 31
|                   |  |                       
|                   |  |                        |    |      |  |      
|                   |  | 2003                   |    | 2002 |  | 2001 
|                   |  |                        |    |      |  |      
|                   |  | Gross                  |    | Net  |  | Gross |    | Net |  | Gross |     | Net
|                   |  |                        |    |      |  |       |    |     |  |       |     |    
|                   |  |                       
|                   |  | (mmbbls)              
|Proved developed   |  |                        | 86 |      |  |       | 73 |     |  |       | 94  |     |  |  | 79 |  |  |  | 109 |  |  |  | 95  | 
|Proved undeveloped |  |                        | 8  |      |  |       | 7  |     |  |       | 13  |     |  |  | 12 |  |  |  | 18  |  |  |  | 16  | 
|                   |  |                        |    |      |  |       |    |     |  |       |     |     |  |  |    |  |  |  |     |  |  |  |     | 
|Total proved       |  |                        | 94 |      |  |       | 80 |     |  |       | 107 |     |  |  | 91 |  |  |  | 127 |  |  |  | 111 | 
|                   |  |                        |    |      |  |       |    |     |  |       |     |     |  |  |    |  |  |  |     |  |  |  |     | 

Heavy Crude Oil Reserves

|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------ |  | ---------------------- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                   |  |                       
|                   |  | Year ended December 31
|                   |  |                       
|                   |  |                        |     |      |  |      
|                   |  | 2003                   |     | 2002 |  | 2001 
|                   |  |                        |     |      |  |      
|                   |  | Gross                  |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                   |  |                        |     |      |  |       |     |     |  |       |     |    
|                   |  |                       
|                   |  | (mmbbls)              
|Proved developed   |  |                        | 156 |      |  |       | 144 |     |  |       | 152 |     |  |  | 139 |  |  |  | 141 |  |  |  | 131 | 
|Proved undeveloped |  |                        | 71  |      |  |       | 66  |     |  |       | 75  |     |  |  | 68  |  |  |  | 91  |  |  |  | 87  | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved       |  |                        | 227 |      |  |       | 210 |     |  |       | 227 |     |  |  | 207 |  |  |  | 232 |  |  |  | 218 | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

Natural Gas Reserves

|                   |  |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 
|------------------ |  | ---------------------- | ----- | ---- |  | ----- | ----- | --- |  | ----- | ----- | --- |  |  | ----- |  |  |  | ----- |  |  |  | ----- | 
|                   |  |                       
|                   |  | Year ended December 31
|                   |  |                       
|                   |  |                        |       |      |  |      
|                   |  | 2003                   |       | 2002 |  | 2001 
|                   |  |                        |       |      |  |      
|                   |  | Gross                  |       | Net  |  | Gross |       | Net |  | Gross |       | Net
|                   |  |                        |       |      |  |       |       |     |  |       |       |    
|                   |  |                       
|                   |  | (bcf)                 
|Proved developed   |  |                        | 1,712 |      |  |       | 1,423 |     |  |       | 1,547 |     |  |  | 1,273 |  |  |  | 1,577 |  |  |  | 1,342 | 
|Proved undeveloped |  |                        | 347   |      |  |       | 294   |     |  |       | 548   |     |  |  | 440   |  |  |  | 389   |  |  |  | 332   | 
|                   |  |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 
|Total proved       |  |                        | 2,059 |      |  |       | 1,717 |     |  |       | 2,095 |     |  |  | 1,713 |  |  |  | 1,966 |  |  |  | 1,674 | 
|                   |  |                        |       |      |  |       |       |     |  |       |       |     |  |  |       |  |  |  |       |  |  |  |       | 

Barrels of Oil Equivalent

|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|------------------ |  | ---------------------- | --- | ---- |  | ----- | --- | --- |  | ----- | --- | --- |  |  | --- |  |  |  | --- |  |  |  | --- | 
|                   |  |                       
|                   |  | Year ended December 31
|                   |  |                       
|                   |  |                        |     |      |  |      
|                   |  | 2003                   |     | 2002 |  | 2001 
|                   |  |                        |     |      |  |      
|                   |  | Gross                  |     | Net  |  | Gross |     | Net |  | Gross |     | Net
|                   |  |                        |     |      |  |       |     |     |  |       |     |    
|                   |  |                       
|                   |  | (mmboe)               
|Proved developed   |  |                        | 727 |      |  |       | 632 |     |  |       | 697 |     |  |  | 601 |  |  |  | 688 |  |  |  | 603 | 
|Proved undeveloped |  |                        | 160 |      |  |       | 140 |     |  |       | 221 |     |  |  | 185 |  |  |  | 239 |  |  |  | 216 | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 
|Total proved       |  |                        | 887 |      |  |       | 772 |     |  |       | 918 |     |  |  | 786 |  |  |  | 927 |  |  |  | 819 | 
|                   |  |                        |     |      |  |       |     |     |  |       |     |     |  |  |     |  |  |  |     |  |  |  |     | 

18



---



##### 



Reserve Life
Index(1)

|                          |  |                        |     |      |  |      |      |  |  |  |      | 
|------------------------- |  | ---------------------- | --- | ---- |  | ---- | ---- |  |  |  | ---- | 
|                          |  |                       
|                          |  | Year ended December 31
|                          |  |                       
|                          |  | 2003                   |     | 2002 |  | 2001
|                          |  |                        |     |      |  |     
|                          |  |                       
|                          |  | (years)               
|Light crude oil & NGL     |  |                        | 8.6 |      |  |      | 9.8  |  |  |  | 14.1 | 
|Medium crude oil          |  |                        | 6.6 |      |  |      | 6.5  |  |  |  | 7.4  | 
|Heavy crude oil           |  |                        | 6.2 |      |  |      | 6.5  |  |  |  | 7.6  | 
|Natural gas               |  |                        | 9.2 |      |  |      | 10.1 |  |  |  | 9.4  | 
|Barrels of oil equivalent |  |                        | 7.8 |      |  |      | 8.4  |  |  |  | 9.3  | 






|    |                                
|--- | -------------------------------
|(1) | Includes total proved reserves.

Reserve
Reconciliation(1)

|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |         |  
|-------------------------------------------------- | --------------------------------------------- | -------------- | ----- | ------------- | - | --------- | ----- | ------- | - | --------- | ----- | --------- | - | ------- | ------- | --------- | - | ------- | ---- | ----- | - |  | ---- | ---- | - |  | ----- | ------ | - |  | ----- | ----- | - |  | ------- | ------- | -
|                                                   |                                               |                |       |               |   |          
|                                                   |                                               | Canada         |       | International |   | Total    
|                                                   |                                               |                |       |               |   |          
|                                                   |                                               |                |       |               |   |           |       |        
|                                                   |                                               | Western Canada |       | East Coast    |   |           |       |        
|                                                   |                                               |                |       |               |   |           |       |        
|                                                   |                                               | Light          |       |               |   |           |       | Light   |   |           |       |          
|                                                   |                                               | Crude Oil      |       | Medium        |   | Heavy     |       | Natural |   | Light     |       | Crude Oil |   | Natural |         | Crude Oil |   | Natural
|                                                   |                                               | & NGL          |       | Crude Oil     |   | Crude Oil |       | Gas     |   | Crude Oil |       | & NGL     |   | Gas     |         | & NGL     |   | Gas    
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |        
|                                                   |                                               | (mmbbls)       |       | (mmbbls)      |   | (mmbbls)  |       | (bcf)   |   | (mmbbls)  |       | (mmbbls)  |   | (bcf)   |         | (mmbbls)  |   | (bcf)  
|Proved reserves, before
    royalties(2)           |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Proved reserves at December 31, 2000               |                                               |                | 181.2 |               |   |           | 135.7 |         |   |           | 186.7 |           |   |         | 1,766.1 |           |   |         | 11.3 |       |   |  | 39.1 |      |   |  | 142.9 |        |   |  | 554.0 |       |   |  | 1,909.0 |        
|                                                   | Revisions                                     |                |       | 6.5           |   |           |       | 0.3     |   |           |       | 18.9      |   |         |         | 22.5      |   |         |      | 1.2   |   |  |      | 0.2  |   |  |       |       |   |  |       | 27.1  |   |  |         | 22.5    |  
|                                                   | Purchases                                     |                |       | 2.4           |   |           |       | 9.5     |   |           |       | 23.7      |   |         |         | 23.7      |   |         |      |      |   |  |      |     |   |  |       |       |   |  |       | 35.6  |   |  |         | 23.7    |  
|                                                   | Sales                                         |                |       |              |   |           |       | (1.8    | ) |           |       |          |   |         |         | (21.1     | ) |         |      |      |   |  |      |     |   |  |       |       |   |  |       | (1.8  | ) |  |         | (21.1   | )
|                                                   | Discoveries, extensions and improved recovery |                |       | 9.0           |   |           |       | 1.0     |   |           |       | 33.3      |   |         |         | 240.7     |   |         |      | 4.8   |   |  |      | 1.2  |   |  |       |       |   |  |       | 49.3  |   |  |         | 240.7   |  
|                                                   | Production                                    |                |       | (16.9         | ) |           |       | (17.2   | ) |           |       | (30.6     | ) |         |         | (209.0    | ) |         |      |      |   |  |      | (0.1 | ) |  |       |       |   |  |       | (64.8 | ) |  |         | (209.0  | )
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Proved reserves at December 31, 2001               |                                               |                | 182.2 |               |   |           | 127.5 |         |   |           | 232.0 |           |   |         | 1,822.9 |           |   |         | 17.3 |       |   |  | 40.4 |      |   |  | 142.9 |        |   |  | 599.4 |       |   |  | 1,965.8 |        
|                                                   | Revisions                                     |                |       | (4.8          | ) |           |       | 9.7     |   |           |       | 7.0       |   |         |         | (37.2     | ) |         |      |      |   |  |      |     |   |  |       |       |   |  |       | 11.9  |   |  |         | (37.2   | )
|                                                   | Purchases                                     |                |       | 0.2           |   |           |       |        |   |           |       | 4.7       |   |         |         | 6.2       |   |         |      |      |   |  |      |     |   |  |       |       |   |  |       | 4.9   |   |  |         | 6.2     |  
|                                                   | Sales                                         |                |       | (1.8          | ) |           |       | (14.2   | ) |           |       | (0.4      | ) |         |         | (19.0     | ) |         |      |      |   |  |      |     |   |  |       |       |   |  |       | (16.4 | ) |  |         | (19.0   | )
|                                                   | Discoveries, extensions and improved recovery |                |       | 5.3           |   |           |       | 0.9     |   |           |       | 18.5      |   |         |         | 386.5     |   |         |      | 18.5  |   |  |      | 1.2  |   |  |       |       |   |  |       | 44.4  |   |  |         | 386.5   |  
|                                                   | Production                                    |                |       | (14.6         | ) |           |       | (16.4   | ) |           |       | (34.7     | ) |         |         | (207.8    | ) |         |      | (4.8  | ) |  |      | (4.5 | ) |  |       |       |   |  |       | (75.0 | ) |  |         | (207.8  | )
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Proved reserves at December 31, 2002               |                                               |                | 166.5 |               |   |           | 107.5 |         |   |           | 227.1 |           |   |         | 1,951.6 |           |   |         | 31.0 |       |   |  | 37.1 |      |   |  | 142.9 |        |   |  | 569.2 |       |   |  | 2,094.5 |        
|                                                   | Revisions                                     |                |       | 5.0           |   |           |       | 1.3     |   |           |       | 6.4       |   |         |         | (131.6    | ) |         |      | 0.8   |   |  |      | (4.5 | ) |  |       | (142.9 | ) |  |       | 9.0   |   |  |         | (274.5  | )
|                                                   | Purchases                                     |                |       | 9.3           |   |           |       |        |   |           |       | 2.8       |   |         |         | 183.9     |   |         |      |      |   |  |      |     |   |  |       |       |   |  |       | 12.1  |   |  |         | 183.9   |  
|                                                   | Sales                                         |                |       | (0.9          | ) |           |       | (2.5    | ) |           |       | (1.4      | ) |         |         | (23.1     | ) |         |      |      |   |  |      |     |   |  |       |       |   |  |       | (4.8  | ) |  |         | (23.1   | )
|                                                   | Discoveries, extensions and improved recovery |                |       | 5.4           |   |           |       | 1.9     |   |           |       | 28.4      |   |         |         | 301.0     |   |         |      |      |   |  |      |     |   |  |       |       |   |  |       | 35.7  |   |  |         | 301.0   |  
|                                                   | Production                                    |                |       | (11.8         | ) |           |       | (14.3   | ) |           |       | (36.5     | ) |         |         | (222.9    | ) |         |      | (6.1  | ) |  |      | (8.2 | ) |  |       |       |   |  |       | (76.9 | ) |  |         | (222.9  | )
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Proved reserves at December 31,
    2003           |                                               |                | 173.5 |               |   |           | 93.9  |         |   |           | 226.8 |           |   |         | 2,058.9 |           |   |         | 25.7 |       |   |  | 24.4 |      |   |  |      |        |   |  | 544.3 |       |   |  | 2,058.9 |        
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Proved developed reserves, before
    royalties(3) |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|                                                   | December 31, 2000                             |                |       | 167.5         |   |           |       | 117.6   |   |           |       | 117.5     |   |         |         | 1,579.9   |   |         |      |      |   |  |      | 0.5  |   |  |       |       |   |  |       | 403.1 |   |  |         | 1,579.9 |  
|                                                   | December 31, 2001                             |                |       | 168.6         |   |           |       | 108.7   |   |           |       | 141.0     |   |         |         | 1,576.5   |   |         |      | 6.2   |   |  |      | 0.6  |   |  |       |       |   |  |       | 425.1 |   |  |         | 1,576.5 |  
|                                                   | December 31, 2002                             |                |       | 154.8         |   |           |       | 93.6    |   |           |       | 152.4     |   |         |         | 1,546.5   |   |         |      | 7.4   |   |  |      | 30.7 |   |  |       |       |   |  |       | 438.9 |   |  |         | 1,546.5 |  
|                                                   | December 31, 2003                             |                |       | 158.5         |   |           |       | 85.8    |   |           |       | 156.2     |   |         |         | 1,712.4   |   |         |      | 17.2  |   |  |      | 24.4 |   |  |       |       |   |  |       | 442.1 |   |  |         | 1,712.4 |  
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|Probable reserves, before
    royalties(4)(5)      |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        
|                                                   | December 31, 2000                             |                |       | 72.4          |   |           |       | 35.2    |   |           |       | 105.7     |   |         |         | 434.1     |   |         |      | 202.3 |   |  |      | 5.3  |   |  |       | 18.9   |   |  |       | 420.9 |   |  |         | 453.0   |  
|                                                   | December 31, 2001                             |                |       | 72.0          |   |           |       | 36.0    |   |           |       | 105.0     |   |         |         | 405.6     |   |         |      | 213.3 |   |  |      | 4.2  |   |  |       | 18.9   |   |  |       | 430.5 |   |  |         | 424.5   |  
|                                                   | December 31, 2002                             |                |       | 70.3          |   |           |       | 24.1    |   |           |       | 152.0     |   |         |         | 383.9     |   |         |      | 201.6 |   |  |      | 4.2  |   |  |       | 18.9   |   |  |       | 452.2 |   |  |         | 402.8   |  
|                                                   | December 31, 2003                             |                |       | 61.0          |   |           |       | 13.8    |   |           |       | 171.3     |   |         |         | 381.3     |   |         |      | 182.2 |   |  |      | 7.0  |   |  |       | 66.5   |   |  |       | 435.3 |   |  |         | 447.8   |  
|                                                   |                                               |                |       |               |   |           |       |         |   |           |       |           |   |         |         |           |   |         |      |       |   |  |      |      |   |  |       |        |   |  |       |       |   |  |         |        






|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Husky applied for and was granted an exemption
    from National Instrument 51-101 Standards of
    Disclosure for Oil and Gas Activities to provide oil and
    gas reserves disclosures in accordance with the
    U.S. Securities and Exchange Commission guidelines and the
    U.S. Financial Accounting Standards Board disclosure
    standards. The information disclosed may differ from information
    prepared in accordance with National Instrument 51-101.
    Huskys internally generated oil and gas reserves data was
    audited by an independent firm of consulting engineers.
|   
|(2) | Proved reserves are the estimated quantities of
    crude oil, natural gas and NGL which geological and engineering
    data demonstrate with reasonable certainty to be recoverable in
    future years from known reservoirs under existing economic and
    operating conditions.                                                                                                                                                                                                                                                                                                                  

19



---



##### 





|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(3) | Proved developed oil and gas reserves are
    reserves that can be expected to be recovered through existing
    wells with existing equipment and operating methods.                                                                                                                                                                                                                                                                                                                                                                                                            
|   
|(4) | Probable reserves are those additional reserves
    that are less certain to be recovered than proved reserves. It
    is equally likely that the actual remaining quantities recovered
    will be greater or less than the sum of the estimated proved
    plus probable reserves (Canadian Oil and Gas Evaluation
    Handbook). The Securities and Exchange Commission in the United
    States does not generally permit disclosure of probable reserves
    to be included in filed documents due to the higher level of
    uncertainty associated with probable reserves.
|   
|(5) | Heavy crude oil probable reserves include bitumen
    located in the oil sands designated regions of Alberta.                                                                                                                                                                                                                                                                                                                                                                                                                                                                    



| |                              
| | -----------------------------
| | Finding and Development Costs

Western
Canada(1)

|                                                   |  |                        |         |      |  |      |         |      |  |   |       |  |  |   |       | 
|-------------------------------------------------- |  | ---------------------- | ------- | ---- |  | ---- | ------- | ---- |  | - | ----- |  |  | - | ----- | 
|                                                   |  |                       
|                                                   |  | Year ended December 31
|                                                   |  |                       
|                                                   |  | 2001-2003              |         | 2003 |  | 2002 |         | 2001
|                                                   |  |                        |         |      |  |      |         |     
|Total capitalized costs ($ millions)               |  | $                      | 3,019.1 |      |  | $    | 1,132.7 |      |  | $ | 994.2 |  |  | $ | 892.2 | 
|Proved reserve additions and revisions
    (mmboe) |  |                        | 284.3   |      |  |      | 76.6    |      |  |   | 94.8  |  |  |   | 112.9 | 
|Average cost per boe                               |  | $                      | 10.62   |      |  | $    | 14.79   |      |  | $ | 10.49 |  |  | $ | 7.90  | 






|    |                                                   
|--- | --------------------------------------------------
|(1) | Excludes oil sands and acquisitions/ divestitures.



| |                       
| | ----------------------
| | Production Replacement

Total

|                                                                                          |  |                        |       |      |  |      |       |      |  |  |       |  |  |  |       | 
|----------------------------------------------------------------------------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ----- | 
|                                                                                          |  |                       
|                                                                                          |  | Year ended December 31
|                                                                                          |  |                       
|                                                                                          |  | 2001-2003              |       | 2003 |  | 2002 |       | 2001
|                                                                                          |  |                        |       |      |  |      |       |     
|Production (mmboe)                                                                        |  |                        | 323.3 |      |  |      | 114.1 |      |  |  | 109.6 |  |  |  | 99.6  | 
|Proved reserve additions and revisions
    (mmboe)                                        |  |                        | 284.0 |      |  |      | 49.1  |      |  |  | 114.5 |  |  |  | 120.4 | 
|Production replacement ratio (excluding
    acquisitions/ divestitures) (percent)         |  |                        | 88    |      |  |      | 43    |      |  |  | 104   |  |  |  | 121   | 
|Proved reserve additions and revisions (including
    acquisitions/ divestitures) (mmboe) |  |                        | 338.6 |      |  |      | 83.2  |      |  |  | 100.9 |  |  |  | 154.5 | 
|Production replacement ratio (including
    acquisitions/ divestitures) (percent)         |  |                        | 105   |      |  |      | 73    |      |  |  | 92    |  |  |  | 155   | 

Western
Canada(1)

|                                                                                          |  |                        |       |      |  |      |       |      |  |  |       |  |  |  |       | 
|----------------------------------------------------------------------------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ----- | 
|                                                                                          |  |                       
|                                                                                          |  | Year ended December 31
|                                                                                          |  |                       
|                                                                                          |  | 2001-2003              |       | 2003 |  | 2002 |       | 2001
|                                                                                          |  |                        |       |      |  |      |       |     
|Production (mmboe)                                                                        |  |                        | 299.4 |      |  |      | 99.7  |      |  |  | 100.2 |  |  |  | 99.5  | 
|Proved reserve additions and revisions
    (mmboe)                                        |  |                        | 284.3 |      |  |      | 76.6  |      |  |  | 94.8  |  |  |  | 112.9 | 
|Production replacement ratio (excluding
    acquisitions/ divestitures) (percent)         |  |                        | 95    |      |  |      | 77    |      |  |  | 95    |  |  |  | 113   | 
|Proved reserve additions and revisions (including
    acquisitions/ divestitures) (mmboe) |  |                        | 338.9 |      |  |      | 110.7 |      |  |  | 81.2  |  |  |  | 147.0 | 
|Production replacement ratio (including
    acquisitions/ divestitures) (percent)         |  |                        | 113   |      |  |      | 111   |      |  |  | 81    |  |  |  | 148   | 






|    |                    
|--- | -------------------
|(1) | Excludes oil sands.



| |              
| | -------------
| | Recycle Ratio

The recycle ratio measures the efficiency of
Huskys capital program by comparing the cost of finding
and developing proved reserves with the netback from production.
The ratio is calculated by dividing the operating netback by the
proved finding and development cost on a boe basis.

20



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##### 



Western
Canada(1)

|                                            |  |                        |       |      |  |      |       |      |  |   |       |  |  |   |       | 
|------------------------------------------- |  | ---------------------- | ----- | ---- |  | ---- | ----- | ---- |  | - | ----- |  |  | - | ----- | 
|                                            |  |                       
|                                            |  | Year ended December 31
|                                            |  |                       
|                                            |  | 2001-2003              |       | 2003 |  | 2002 |       | 2001
|                                            |  |                        |       |      |  |      |       |     
|Operating netback ($/boe)                   |  | $                      | 16.60 |      |  | $    | 18.40 |      |  | $ | 16.09 |  |  | $ | 15.30 | 
|Proved finding and development cost ($/boe) |  | $                      | 10.62 |      |  | $    | 14.79 |      |  | $ | 10.49 |  |  | $ | 7.90  | 
|Recycle ratio                               |  |                        | 1.56  |      |  |      | 1.24  |      |  |   | 1.53  |  |  |   | 1.94  | 






|    |                    
|--- | -------------------
|(1) | Excludes oil sands.

Undeveloped Land Holdings

|                                 |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |       | 
|-------------------------------- | ---------------- | ---------------------- | ------ | ----- |  | ----- | ------ | ----- |  |  | ------ | ----- |  |  | ------ | ----- | 
|                                 |                  |                       
|                                 |                  | Year ended December 31
|                                 |                  |                       
|                                 |                  |                        |        |      
|                                 |                  | 2003                   |        | 2002 
|                                 |                  |                        |        |      
|                                 |                  | Gross                  |        | Net   |  | Gross |        | Net  
|                                 |                  |                        |        |       |  |       |        |      
|                                 |                  |                       
|                                 |                  | (thousands of acres)  
|Western Canada                   |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |      
|                                 | Alberta          |                        |        | 5,508 |  |       |        | 4,852 |  |  |        | 5,416 |  |  |        | 4,907 | 
|                                 | Saskatchewan     |                        |        | 2,057 |  |       |        | 1,911 |  |  |        | 2,098 |  |  |        | 1,986 | 
|                                 | British Columbia |                        |        | 713   |  |       |        | 491   |  |  |        | 314   |  |  |        | 273   | 
|                                 | Manitoba         |                        |        | 9     |  |       |        | 8     |  |  |        | 13    |  |  |        | 13    | 
|                                 |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |      
|                                 |                  |                        | 8,287  |       |  |       | 7,262  |       |  |  | 7,841  |       |  |  | 7,179  |      
|Northwest Territories and Arctic |                  |                        | 527    |       |  |       | 184    |       |  |  | 463    |       |  |  | 175    |      
|Eastern Canada                   |                  |                        | 2,414  |       |  |       | 2,104  |       |  |  | 2,414  |       |  |  | 2,104  |      
|                                 |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |      
|Total Canada                     |                  |                        | 11,228 |       |  |       | 9,550  |       |  |  | 10,718 |       |  |  | 9,458  |      
|International                    |                  |                        | 4,464  |       |  |       | 2,066  |       |  |  | 4,464  |       |  |  | 2,066  |      
|                                 |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |      
|Total                            |                  |                        | 15,692 |       |  |       | 11,616 |       |  |  | 15,182 |       |  |  | 11,524 |      
|                                 |                  |                        |        |       |  |       |        |       |  |  |        |       |  |  |        |      

21



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##### 



LIQUIDITY

Sources of Capital

As at December 31, 2003 Huskys
outstanding long-term debt totalled $1,698 million,
including amounts due within one year, compared with
$2,385 million at December 31, 2002.

At December 31, 2003 Husky had no funds
drawn under its $830 million revolving syndicated credit
facility. Interest rates under this facility vary and are based
on Canadian prime, Bankers Acceptance, U.S. LIBOR or
U.S. base rate, depending on the borrowing option selected,
credit ratings assigned by certain rating agencies to the
Companys senior unsecured debt and whether the facility is
revolving or non-revolving. The syndicated credit facility
requires Husky to maintain a debt to cash flow ratio of less
than three times and a consolidated net worth of at least
$3.6 billion.

At December 31, 2003 Husky had no funds
drawn under its $100 million credit facility. The terms of
this facility are substantially the same as the syndicated
credit facility.

At December 31, 2003 the Company had drawn
$71 million and utilized in support of letters of credit
$18 million of its $195 million in short-term
borrowing facilities. The interest rates applicable to these
facilities vary and are based on Canadian prime, Bankers
Acceptance, money market rates or U.S. dollar equivalents.
In addition, Husky utilized $88 million under dedicated
letter of credit facilities.

The Company has an agreement to sell up to
$250 million of net trade receivables on a revolving basis.
The agreement calls for purchase discounts, based on Canadian
commercial paper rates, to be paid on an ongoing basis. As at
December 31, 2003, $250 million of net trade
receivables had been sold under this agreement. The arrangement
matures on January 31, 2009.

The Company believes that, based on its current
forecast for commodity prices for 2004, its 2004 capital program
of $2.1 billion and non-cancellable cash contractual
obligations and commitments will be funded by operating
activities and, to the extent required, available credit
facilities. In the event of significantly lower cash flow, the
Company would be able to defer certain of its capital spending
programs without penalty.

The Company declared dividends that aggregated
$1.38 per share ($580 million) in 2003 including a special
dividend of $1.00 per share. The Board of Directors of Husky has
established a dividend policy that pays quarterly dividends of
$0.10 ($0.40 annually) per common share. The declaration of
dividends will be at the discretion of the Board of Directors,
which will consider earnings, capital requirements, financial
condition of the Company and other relevant factors.

Cash and cash equivalents at December 31,
2003 totalled $3 million compared with $306 million at
the beginning of the year.

Financial Ratios

|                                                  |  |                        |        |      |  |      |        |   |  |   |        |  
|------------------------------------------------- |  | ---------------------- | ------ | ---- |  | ---- | ------ | - |  | - | ------ | -
|                                                  |  |                       
|                                                  |  | Year ended December 31
|                                                  |  |                       
|                                                  |  | 2003                   |        | 2002 |  | 2001
|                                                  |  |                        |        |      |  |     
|Cash flow  operating activities
    ($ millions) |  | $                      | 2,572  |      |  | $    | 1,892  |   |  | $ | 1,930  |  
| financing activities
    ($ millions)           |  | $                      | (800   | )    |  | $    | 3      |   |  | $ | (423   | )
| investing activities
    ($ millions)           |  | $                      | (2,075 | )    |  | $    | (1,589 | ) |  | $ | (1,507 | )
|Debt to capital employed (percent)                |  |                        | 23.1   |      |  |      | 31.8   |   |  |   | 32.8   |  
|Debt to cash flow from operations (times)         |  |                        | 0.7    |      |  |      | 1.1    |   |  |   | 1.1    |  
|Corporate reinvestment ratio (1)                  |  |                        | 0.9    |      |  |      | 0.8    |   |  |   | 0.8    |  






|    |                                                                              
|--- | -----------------------------------------------------------------------------
|(1) | Capital and investment expenditures divided by
    cash flow from operations.

Credit Ratings

Husky receives debt ratings from three major
rating agencies. In determining Huskys debt rating the
agencies evaluate several factors including, but not limited to,
the industry Husky operates in, volatility of the industry, the
geographical and business diversity and quality of the
Companys asset base, near- and long-term production growth
opportunities, capital allocation and cost structure issues,
capital structure and character of oil and gas reserves. There
are debt rating features in Huskys debt covenants that
cause a change in interest rates in certain debt facilities and
may cause the issuance of letters of credit pursuant to the
terms of certain commercial contracts. In addition the
Companys

22



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##### 



debt ratings could affect the ability of the
Company to secure new or additional credit facilities if the
rating falls below investment grade.


At December 31, 2003 Husky had the following
credit ratings:

|                                       |  |                                  |  |        |            | 
|-------------------------------------- |  | -------------------------------- |  | ------ | ---------- | 
|                                       |  | Debt Rated                       |  | Rating
|                                       |  |                                  |  |       
|Standard and Poors Rating
    Service |  | Outlook                          |  |        | Positive   | 
|                                       |  | Senior unsecured debt            |  |        | BBB        | 
|                                       |  | 8.45% senior secured bonds       |  |        | BBB        | 
|                                       |  | Capital securities               |  |        | BB+        | 
|Moodys Investor Service               |  | Outlook                          |  |        | Stable     | 
|                                       |  | Senior unsecured debt            |  |        | Baa2       | 
|                                       |  | 8.45% senior secured bonds       |  |        | Baa2       | 
|                                       |  | Capital securities               |  |        | Ba1        | 
|Dominion Bond Rating Service           |  | Outlook                          |  |        | Stable     | 
|                                       |  | Senior unsecured long-term notes |  |        | BBB (high) | 
|                                       |  | Capital securities               |  |        | BBB        | 

Capital Requirements

Husky plans to invest capital in the following
segments in 2004:

|                 |                   |               |       |       | 
|---------------- | ----------------- | ------------- | ----- | ----- | 
|                 |                   | Year ended   
|                 |                   | December 31  
|                 |                   |              
|                 |                   | 2004 Estimate
|                 |                   |              
|                 |                   | ($ millions) 
|Upstream         |                   |               |       |      
|                 | Western Canada    |               | $     | 1,150 | 
|                 | East Coast Canada |               |       | 585   | 
|                 | International     |               |       | 65    | 
|                 |                   |               |       |      
|                 |                   |               | 1,800 |      
|Midstream        |                   |               | 100   |      
|Refined Products |                   |               | 150   |      
|Corporate        |                   |               | 30    |      
|                 |                   |               |       |      
|                 |                   | $             | 2,080 |      
|                 |                   |               |       |      

In order to retain undeveloped acreage Husky is
required to drill wells within a certain time frame otherwise
the acreage is relinquished. In order to maintain its
undeveloped acreage at current retention rates over the period
2004 to 2007, Husky estimates drilling expenditures of
approximately $75 million in 2004, $65 million in 2005
and $45 million during both 2006 and 2007.

Contractual Obligations and Commercial
Commitments

In the normal course of business Husky is
obligated to make future payments. These obligations represent
contracts and other commitments that are known and
non-cancellable.

23



---



##### 



Contractual Obligations

|                                         |  |       |       |                        |  |           |       |            |  |   |     |  |  |   |       | 
|---------------------------------------- |  | ----- | ----- | ---------------------- |  | --------- | ----- | ---------- |  | - | --- |  |  | - | ----- | 
|                                         |  |       |       |                        |  |          
|                                         |  |       |       | Payments Due by Period |  |          
|                                         |  |       |       |                        |  |          
|                                         |  | Total |       | 2004-2006              |  | 2007-2008 |       | Thereafter
|                                         |  |       |       |                        |  |           |       |           
|                                         |  |       |       |                        |  |          
|                                         |  |       |       | ($ millions)           |  |          
|Long-term debt                           |  | $     | 1,698 |                        |  | $         | 545   |            |  | $ | 146 |  |  | $ | 1,007 | 
|Capital securities                       |  |       | 291   |                        |  |           |      |            |  |   |    |  |  |   | 291   | 
|Operating leases                         |  |       | 514   |                        |  |           | 194   |            |  |   | 145 |  |  |   | 175   | 
|Firm transportation agreements           |  |       | 1,788 |                        |  |           | 679   |            |  |   | 369 |  |  |   | 740   | 
|Unconditional purchase obligations       |  |       | 915   |                        |  |           | 776   |            |  |   | 124 |  |  |   | 15    | 
|Exploration lease agreements             |  |       | 497   |                        |  |           | 167   |            |  |   | 97  |  |  |   | 233   | 
|Engineering and construction commitments |  |       | 597   |                        |  |           | 597   |            |  |   |    |  |  |   |      | 
|                                         |  |       |       |                        |  |           |       |            |  |   |     |  |  |   |       | 
|                                         |  | $     | 6,300 |                        |  | $         | 2,958 |            |  | $ | 881 |  |  | $ | 2,461 | 
|                                         |  |       |       |                        |  |           |       |            |  |   |     |  |  |   |       | 

Investment Canada
Undertakings

In respect of the acquisition of Marathon Canada,
Husky confirmed certain undertakings to the Minister Responsible
for the Investment Canada Act. The undertakings included capital
expenditures on the purchased and retained Marathon Canada lands
amounting to $65 million, spending on community activities
amounting to $1.35 million and environmental expenditures
of $40 million, all to occur in 2004.

Asset Retirement Obligations

The above table does not include asset retirement
obligations. The Company currently includes such obligations in
the amortizing base of its oil and gas properties. Effective
January 1, 2004 with the adoption of the Canadian Institute
of Chartered Accountants (CICA) section 3110,
Asset Retirement Obligations, the Company will
record a separate liability for the fair value of its asset
retirement obligations. See note 20 to the Consolidated
Financial Statements.

Post-retirement Benefit
Obligations

The above table does not include post-retirement
obligations. Husky has a defined contribution pension plan and a
post-retirement health and dental care plan for its employees.
In addition Husky has a defined benefit pension plan for
approximately 230 employees. In 1991 admittance to the defined
benefit pension plan ended after the majority of members
transferred to the newly created defined contribution pension
plan.

Other Obligations

Husky is also subject to various contingent
obligations that become payable only if certain events or
rulings were to occur. The inherent uncertainty surrounding the
timing and financial impact of these events or rulings prevents
any meaningful measurement, which is necessary to assess impact
on future liquidity. Such obligations include environmental
contingencies, contingent consideration and potential
settlements resulting from litigation.

Off Balance Sheet Arrangements

Husky does not currently utilize any off balance
sheet arrangements with unconsolidated entities to enhance
liquidity and capital resource positions or for any other
purpose.

24



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##### 



TRANSACTIONS WITH RELATED PARTIES AND MAJOR
CUSTOMERS

Husky, in the ordinary course of business,
entered into a lease for an eight-year term effective
September 1, 2000 with Western Canadian Place Ltd. The
terms of the lease provide for the lease of office space,
management services and operating costs at commercial rates.
Western Canadian Place Ltd. is indirectly controlled by
Huskys principal shareholders. During 2003 Husky paid
approximately $17 million for office space in Western
Canadian Place.

Husky did not have any customers that constituted
more than five percent of total sales and operating revenues
during 2003.

FINANCIAL AND DERIVATIVE INSTRUMENTS

Husky is exposed to market risks related to the
volatility of commodity prices, foreign exchange rates and
interest rates. Refer to the section Business
Environment. Husky, from time to time, uses derivative
instruments to manage its exposure to these risks.

Commodity Price Risk Management

Husky uses derivative commodity instruments to
manage exposure to price volatility on a portion of its oil and
gas production and firm commitments for the purchase or sale of
crude oil and natural gas.

The Company implemented a corporate hedging
program for 2004 to manage the volatility of natural gas and
crude oil prices.

Natural Gas

The 2003 natural gas hedging program was in
effect from April 2003 to December 2003. During that period
Husky received net payments totalling $24 million on these
contracts.

At December 31, 2003 Husky had natural gas
swap agreements in place to hedge 2004 production. The contracts
were as follows:

Natural Gas Hedges

|                  |  |                  |    |      |  |       |               |              |  |  |                   |  |  |   |   | 
|----------------- |  | ---------------- | -- | ---- |  | ----- | ------------- | ------------ |  |  | ----------------- |  |  | - | - | 
|                  |  |                  |    |      |  |       |               | Unrecognized
|                  |  | Notional Volumes |    | Term |  | Price |               | Gain/(Loss) 
|                  |  |                  |    |      |  |       |               |             
|                  |  | (mmcf/day)       |    |      |  |       |               | ($ millions)
|NYMEX fixed price |  |                  | 70 |      |  |       | February 2004 |              |  |  | U.S.  $6.69/mmbtu |  |  | $ | 1 | 
|                  |  |                  | 70 |      |  |       | March 2004    |              |  |  | U.S.  $6.69/mmbtu |  |  |   | 2 | 
|                  |  |                  | 20 |      |  |       | April 2004    |              |  |  | U.S.  $6.38/mmbtu |  |  |   | 1 | 
|                  |  |                  |    |      |  |       |               |              |  |  |                   |  |  |   |   | 
|                  |  |                  |    |      |  |       |               |              |  |  |                   |  |  | $ | 4 | 
|                  |  |                  |    |      |  |       |               |              |  |  |                   |  |  |   |   | 

Crude Oil

Crude oil hedges on 27.6 mmbbls were in
effect from January to December 2003. During that period Husky
recorded net payments totalling $36 million on these
contracts.

Husky had a put option contract in effect from
July to December 2003 on 3.7 mmbbls of crude oil with a
strike price of U.S. $27/bbl. The contract was a full-term
settlement contract. Husky paid $8 million for the contract
which was charged to earnings over the contract period.

At December 31, 2003 Husky had crude oil
swap agreements in place to hedge 2004 production. The contracts
were as follows:

Crude Oil Hedges

|                  |  |                  |    |      |  |       |                   |              |  |         |           |  |  |   |      |  
|----------------- |  | ---------------- | -- | ---- |  | ----- | ----------------- | ------------ |  | ------- | --------- |  |  | - | ---- | -
|                  |  |                  |    |      |  |       |                   | Unrecognized
|                  |  | Notional Volumes |    | Term |  | Price |                   | Gain/(Loss) 
|                  |  |                  |    |      |  |       |                   |             
|                  |  | (mbbls/day)      |    |      |  |       |                   | ($ millions)
|NYMEX fixed price |  |                  | 85 |      |  |       | Jan. to Dec. 2004 |              |  | U.S.  $ | 27.46/bbl |  |  | $ | (109 | )

25



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##### 



Power Consumption

At December 31, 2003 Husky had hedged power
consumption as follows:

Power Consumption Hedges

|                     |  |                  |      |      |  |       |                   |              |  |   |           |  |  |   |   | 
|-------------------- |  | ---------------- | ---- | ---- |  | ----- | ----------------- | ------------ |  | - | --------- |  |  | - | - | 
|                     |  |                  |      |      |  |       |                   | Unrecognized
|                     |  | Notional Volumes |      | Term |  | Price |                   | Gain/(Loss) 
|                     |  |                  |      |      |  |       |                   |             
|                     |  | (MW)             |      |      |  |       |                   | ($ millions)
|Fixed price purchase |  |                  | 20.0 |      |  |       | Jan. to Dec. 2004 |              |  | $ | 46.25/MWh |  |  | $ | 1 | 
|                     |  |                  | 17.5 |      |  |       | Jan. to Dec. 2004 |              |  | $ | 47.25/MWh |  |  |   | 1 | 
|                     |  |                  |      |      |  |       |                   |              |  |   |           |  |  |   |   | 
|                     |  |                  |      |      |  |       |                   |              |  |   |           |  |  | $ | 2 | 
|                     |  |                  |      |      |  |       |                   |              |  |   |           |  |  |   |   | 

Foreign Currency Risk Management

At December 31, 2003, the Company had the
following cross currency debt swaps in place:



| |   |                                                                                                                       
| | - | ----------------------------------------------------------------------------------------------------------------------
| |  | U.S. $150 million at 7.125 percent
    swapped at $1.4500 to $218 million at 8.74 percent
    until November 15, 2006.
|
| |  | U.S. $150 million at 6.250 percent
    swapped at $1.4100 to $212 million at 7.41 percent
    until June 15, 2012.    

At December 31, 2003 the cost of a
U.S. dollar in Canadian currency was $1.2924.

In 2003 the cross currency swaps resulted in an
offset to foreign exchange gains on translation of
U.S. dollar denominated debt amounting to $73 million.

Interest Rate Risk Management

In 2003 the interest rate risk management
activities resulted in a decrease to interest expense of
$17 million.

The cross currency swaps resulted in an addition
to interest expense of $13 million in 2003.

Husky has an interest rate swap on
$200 million of long-term debt effective February 8,
2002 whereby 6.95 percent was swapped for CDOR + 175
bps until July 14, 2009. During 2003 this swap resulted in
an offset to interest expense amounting to $4 million.

Husky has an interest rate swap on
U.S. $200 million of long-term debt effective
February 12, 2002 whereby 7.55 percent was swapped for
an average U.S. LIBOR + 194 bps until
November 15, 2011. During 2003 this swap resulted in an
offset to interest expense amounting to $12 million.

Husky had three interest rate swaps that were
unwound in 2003. During 2003, the impact of these three swaps
before they were unwound was an offset to interest expense of
$6 million. The amortization of the swap terminations
resulted in an additional $8 million offset to interest
expense.

26



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##### 



APPLICATION OF CRITICAL ACCOUNTING
ESTIMATES

Huskys financial statements have been
prepared in accordance with generally accepted accounting
principles. The significant accounting policies used by Husky
are disclosed in note 3 to the Consolidated Financial
Statements. Certain accounting policies require that management
make appropriate decisions with respect to the formulation of
estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues and expenses. The following
discusses such accounting policies and is included in
Managements Discussion and Analysis to aid the reader in
assessing the critical accounting policies and practices of the
Company and the likelihood of materially different results being
reported. Huskys management reviews its estimates
regularly. The emergence of new information and changed
circumstances may result in actual results or changes to
estimated amounts that differ materially from current estimates.

The following assessment of significant
accounting policies is not meant to be exhaustive. The Company
might realize different results from the application of new
accounting standards promulgated, from time to time, by various
rule-making bodies.

Proved Oil and Gas Reserves

Proved oil and gas reserves, as defined by the
U.S. Securities and Exchange Commission Regulation S-X
Rule 4-10, are the estimated quantities of crude oil,
natural gas liquids including condensate and natural gas that
geological and engineering data demonstrate with reasonable
certainty can be recovered in future years from known reservoirs
under existing economic and operating conditions, i.e., prices
and costs as of the date the estimate is made.

Reserves are considered proved if they can be
produced economically as demonstrated by either actual
production or conclusive formation tests. Reserves which must be
produced through the application of enhanced recovery techniques
are included in the proved category only after successful
testing by a pilot project or operation of an installed program
in the same reservoir that provides support for the engineering
analysis on which the project was based. Proved developed
reserves are expected to be produced through existing wells and
with existing facilities and operating methods.

The oil and gas reserve estimates are made using
all available geological and reservoir data as well as
historical production data. Estimates are reviewed and revised
as appropriate. Revisions occur as a result of changes in
prices, costs, fiscal regimes, reservoir performance or a change
in the Companys plans. The effect of changes in proved oil
and gas reserves on the financial results and position of the
Company is described under the heading Full Cost
Accounting for Oil and Gas Activities.

Full Cost Accounting for Oil and Gas
Activities

Depletion Expense

The Company uses the full cost method of
accounting for exploration and development activities. In
accordance with this method of accounting, all costs associated
with exploration and development are capitalized whether
successful or not. The aggregate of net capitalized costs and
estimated future development costs less estimated salvage values
is amortized using the unit of production method based on
estimated proved oil and gas reserves.

An increase in estimated proved oil and gas
reserves would result in a corresponding reduction in depletion
expense. A decrease in estimated future development costs would
result in a corresponding reduction in depletion expense.

Withheld Costs

Certain costs related to unproved properties and
major development projects may be excluded from costs subject to
depletion until proved reserves have been determined or their
value is impaired. These properties are reviewed quarterly and
any impairment is transferred to the costs being depleted or, if
the properties are located in a cost centre where there is no
reserve base, the impairment is charged directly to earnings.

Impairment of Long-lived Assets

The Company is required to review the carrying
value of all property, plant and equipment, including the
carrying value of oil and gas assets, for potential impairment.
Impairment is indicated if the carrying value of the long-lived
asset or oil and gas cost centre is not recoverable by the
future undiscounted cash flows. If impairment is indicated, the
amount by which the carrying value exceeds the estimated fair
value of the long-lived asset is charged to earnings.

27



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##### 



Fair Value of Derivative Instruments

Periodically Husky utilizes financial derivatives
to manage market risk. The purpose of the hedge is to provide an
element of stability to Huskys cash flow in a volatile
environment. Husky discloses the estimated fair value of open
hedging contracts as at the end of a reporting period. Effective
January 1, 2004 Husky will adopt CICA Accounting
Guideline 13, Hedging Relationships
(AcG-13). AcG-13 has essentially the same criteria
to be satisfied before the application of hedge accounting is
permitted as the corresponding requirements of the Financial
Accounting Standards Board (FASB) Statement
No. 133, Accounting for Derivative Instruments and
Hedging Activities (FAS 133). Refer to
the description of FAS 133 in note 20 to the
Consolidated Financial Statements.

The estimation of the fair value of certain
hedging derivatives requires considerable judgement. The
estimation of the fair value of commodity price hedges requires
sophisticated financial models that incorporate forward price
and volatility data and, which when compared with Huskys
open hedging contracts, produce cash inflow or outflow variances
over the contract period. The estimate of fair value for
interest rate and foreign currency hedges is determined
primarily through quotes from financial institutions.

Accounting rules for transactions involving
derivative instruments are complex and subject to a range of
interpretation. The FASB has established the Derivative
Implementation Group task force, which, on an ongoing basis,
considers issues arising from interpretation of these accounting
rules. The potential exists that the task force may promulgate
interpretations that differ from those of the Company. In this
event the Companys policy would be modified.

Asset Retirement Obligations

Effective January 1, 2004 the Company will
change its accounting policy with respect to accounting for
asset retirement obligations. CICA section 3110,
essentially the same as FASBs Statement No. 143,
Accounting for Asset Retirement Obligations
(FAS 143), requires the fair value of asset
retirement obligations to be recorded when they are incurred
rather than merely accumulated or accrued over the useful life
of the respective asset.

The Company, under the current policy, is
required to provide for future removal and site restoration
costs. The Company must estimate these costs in accordance with
existing laws, contracts or other policies. These estimated
costs are charged to earnings and the appropriate liability
account over the expected service life of the asset. When the
future removal and site restoration costs cannot be reasonably
determined, a contingent liability may exist. Contingent
liabilities are charged to earnings when management is able to
determine the amount and the likelihood of the future obligation.

Legal, Environmental Remediation and Other
Contingent Matters

The Company is required to both determine whether
a loss is probable based on judgement and interpretation of laws
and regulations and determine that the loss can reasonably be
estimated. When the loss is determined it is charged to
earnings. The Companys management must continually monitor
known and potential contingent matters and make appropriate
provisions by charges to earnings when warranted by circumstance.

Income Tax Accounting

The determination of the Companys income
and other tax liabilities requires interpretation of complex
laws and regulations often involving multiple jurisdictions. All
tax filings are subject to audit and potential reassessment
after the lapse of considerable time. Accordingly, the actual
income tax liability may differ significantly from that
estimated and recorded by management.

Business Combinations

Over recent years Husky has grown considerably
through combining with other businesses. Husky acquired Marathon
Canada in 2003. This transaction was accounted for using what is
now the only accounting method available, the purchase method.
Under the purchase method, the acquiring company includes the
fair value of the assets of the acquired entity on its balance
sheet. The determination of fair value necessarily involves many
assumptions. The valuation of oil and gas properties primarily
relies on placing a value on the oil and gas reserves. The
valuation of oil and gas reserves entails the process described
above under the caption Proved Oil and Gas Reserves
but in contrast incorporates the use of economic forecasts that
estimate future changes in prices and costs. In addition this

28



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##### 



methodology is used to value unproved oil and gas
reserves. The valuation of these reserves, by their nature, is
less certain than the valuation of proved reserves.


Goodwill

The process of accounting for the purchase of a
company, described above, results in recognizing the fair value
of the acquired companys assets on the balance sheet of
the acquiring company. Any excess of the purchase price over
fair value is recorded as goodwill. Since goodwill results from
the culmination of a process that is inherently imprecise the
determination of goodwill is also imprecise. In accordance with
the recent issuance of FASB Statement No. 142 and CICA
section 3062, Goodwill and Other Intangible
Assets, goodwill is no longer amortized but assessed
periodically for impairment. The process of assessing goodwill
for impairment necessarily requires Husky to determine the fair
value of its assets and liabilities. Such a process involves
considerable judgement.

29



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##### 



NEW ACCOUNTING STANDARDS

Asset Retirement Obligations

In June 2001 the FASB issued FAS 143,
Accounting for Asset Retirement Obligations.
FAS 143 was effective January 1, 2003 for
U.S. reporting purposes. The Canadian version of
FAS 143, CICA section 3110, which is essentially the
same, is effective January 1, 2004. These new methods for
accounting for asset retirement obligations require an entity to
record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When initially
recorded, the liability is added to the related property, plant
and equipment, subsequently increasing depletion, depreciation
and amortization expense. In addition, the liability is accreted
for the change in present value in each period. Upon adoption of
CICA section 3110, the Company will adjust its existing
future removal and site restoration liability retroactively with
restatement.

The Company has estimated that the cumulative
effect will be an increase of the future removal and site
restoration liability of $129 million, an increase of
related net property, plant and equipment of $164 million,
an increase to the future income tax liability of
$13 million and an increase in retained earnings of
$22 million.

Accounting for Derivative Instruments and
Hedging Activities

In June 1998 the FASB issued FAS 133,
Accounting for Derivative Instruments and Hedging
Activities. This was followed in June 2000 when the FASB
promulgated FAS 138, which amended FAS 133 and
FAS 149, a further modification that was effective for
contracts entered into or modified after June 30, 2003. In
Canada the Accounting Standards Board (AcSB) intends
to bring Canadian accounting standards into line with those in
the U.S. by a two-stage approach. The first stage is an
amendment to AcG-13, Hedging Relationships, which is
effective January 1, 2004 and establishes criteria to be
satisfied before hedge accounting may be applied. The second
stage comprises three exposure drafts that were issued on
March 31, 2003. The culmination of stage two is expected to
complete the harmonization of the Canadian accounting for
derivatives, for all intents and purposes, with U.S. GAAP.

These accounting standards require that every
derivative instrument, including certain derivative instruments
embedded in other contracts, be recorded on the balance sheet as
either an asset or liability measured at fair value. These
standards further establish that changes in the fair value be
recognized currently in earnings unless the arrangement can meet
the effective hedge criteria.

Stock-based Compensation Plans

In October 1995 the FASB issued Statement
No. 123, Accounting for Stock-based Compensation
Plans (FAS 123), which established a fair
value method of accounting for stock-based compensation and
required companies that continued to account for stock-based
compensation in accordance with the intrinsic method
to provide a pro forma disclosure that reflects the difference
between the two methods. In January 2003 the FASB issued
FAS 148, an amendment to FAS 123, which provides
alternative methods of transition for a voluntary change to the
fair value based method of accounting for stock-based employee
compensation. The FASB plans to issue another exposure draft in
the first quarter of 2004 and issue the final statement in the
second quarter of 2004. Effective January 1, 2004 CICA
section 3870, Stock-based Compensation and Other
Stock-based Payments, will require all public companies to
expense all stock-based compensation. This standard provides for
the retroactive adoption of fair value accounting effective
January 1, 2004. After January 1, 2004 the fair value
of stock-based compensation will be recognized as an expense in
the financial statements.

Oil and Gas Full Cost Accounting

In July 2003 the AcSB issued Accounting
Guideline 16, Oil and Gas Accounting  Full
Cost (AcG-16), replacing AcG-5. AcG-16
provides for methodology consistent with CICA section 3063,
Impairment of Long-lived Assets, CICA
section 3475, Disposal of Long-lived Assets and
Discontinued Operations and FASB Statement No. 144,
Accounting for the Impairment and Disposal of Long-lived
Assets.

The new standards prescribe the recognition of
impairment only if the carrying amount of a long-lived asset is
not recoverable from its undiscounted cash flows and measure the
impairment amount as the difference between the carrying amount
and the fair value. In addition, discontinued operations
disclosure will be required upon the disposition of a component
or cost centre of the entity rather than an entire business
segment.

30



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##### 



Quarterly Financial Summary

|                                                                     |                       |                                      |        |         |  |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |         | 
|-------------------------------------------------------------------- | --------------------- | ------------------------------------ | ------ | ------- |  | -- | ------ | ------- |  | -- | ------ | ------- |  | -- | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- |  | - | ------ | ------- | 
|                                                                     |                       |                                      |        |        
|                                                                     |                       | 2003                                 |        | 2002   
|                                                                     |                       |                                      |        |        
|                                                                     |                       | Q4                                   |        | Q3      |  | Q2 |        | Q1      |  | Q4 |        | Q3      |  | Q2 |        | Q1     
|                                                                     |                       |                                      |        |         |  |    |        |         |  |    |        |         |  |    |        |        
|                                                                     |                       |                                     
|                                                                     |                       | ($ millions, except where indicated)
|Sales and operating revenues, net of royalties                       |                       | $                                    | 1,800  |         |  | $  | 1,871  |         |  | $  | 1,769  |         |  | $  | 2,218  |         |  | $ | 1,697  |         |  | $ | 1,669  |         |  | $ | 1,659  |         |  | $ | 1,359  |        
|Net earnings                                                         |                       | $                                    | 245    |         |  | $  | 243    |         |  | $  | 427    |         |  | $  | 406    |         |  | $ | 242    |         |  | $ | 173    |         |  | $ | 263    |         |  | $ | 126    |        
|Earnings per share                                                   |                       |                                      |        |         |  |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                     | Basic                 |                                      | $      | 0.62    |  |    | $      | 0.55    |  |    | $      | 1.06    |  |    | $      | 1.01    |  |   | $      | 0.57    |  |   | $      | 0.38    |  |   | $      | 0.64    |  |   | $      | 0.29    | 
|                                                                     | Diluted               |                                      | $      | 0.62    |  |    | $      | 0.54    |  |    | $      | 1.05    |  |    | $      | 1.00    |  |   | $      | 0.57    |  |   | $      | 0.38    |  |   | $      | 0.64    |  |   | $      | 0.29    | 
|Cash flow from operations                                            |                       | $                                    | 568    |         |  | $  | 604    |         |  | $  | 540    |         |  | $  | 747    |         |  | $ | 635    |         |  | $ | 590    |         |  | $ | 498    |         |  | $ | 373    |        
|Share price                                                          |                       |                                      |        |         |  |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                     | High                  |                                      | $      | 23.95   |  |    | $      | 20.95   |  |    | $      | 18.14   |  |    | $      | 17.49   |  |   | $      | 17.20   |  |   | $      | 17.00   |  |   | $      | 17.98   |  |   | $      | 17.80   | 
|                                                                     | Low                   |                                      | $      | 20.40   |  |    | $      | 17.35   |  |    | $      | 16.15   |  |    | $      | 16.03   |  |   | $      | 15.43   |  |   | $      | 14.00   |  |   | $      | 15.85   |  |   | $      | 14.20   | 
|                                                                     | Close (end of period) |                                      | $      | 23.47   |  |    | $      | 20.50   |  |    | $      | 17.50   |  |    | $      | 16.93   |  |   | $      | 16.47   |  |   | $      | 16.70   |  |   | $      | 16.66   |  |   | $      | 17.10   | 
|Shares traded (thousands)                                            |                       |                                      | 22,171 |         |  |    | 35,453 |         |  |    | 24,858 |         |  |    | 18,371 |         |  |   | 20,478 |         |  |   | 30,620 |         |  |   | 31,159 |         |  |   | 34,383 |        
|Dividends declared per share                                         |                       | $                                    | 0.10   |         |  | $  | 1.10   |         |  | $  | 0.09   |         |  | $  | 0.09   |         |  | $ | 0.09   |         |  | $ | 0.09   |         |  | $ | 0.09   |         |  | $ | 0.09   |        
|Number of weighted average common shares
    outstanding (thousands) |                       |                                      |        |         |  |    |        |         |  |    |        |         |  |    |        |         |  |   |        |         |  |   |        |         |  |   |        |         |  |   |        |        
|                                                                     | Basic                 |                                      |        | 421,702 |  |    |        | 419,729 |  |    |        | 418,539 |  |    |        | 418,163 |  |   |        | 417,748 |  |   |        | 417,497 |  |   |        | 417,393 |  |   |        | 416,939 | 
|                                                                     | Diluted               |                                      |        | 423,830 |  |    |        | 422,010 |  |    |        | 420,331 |  |    |        | 419,985 |  |   |        | 419,567 |  |   |        | 419,136 |  |   |        | 419,558 |  |   |        | 418,951 | 

31



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RESULTS OF OPERATIONS FOR 2002 COMPARED WITH
2001

The consolidated revenue during 2002 was three
percent lower than in 2001 primarily as a result of lower
natural gas prices. The effect of lower natural gas prices was
most evident in the infrastructure and marketing segment with
respect to natural gas marketing revenues.

Net earnings in 2002 were $804 million
compared with $654 million in 2001. The increase of
$150 million was attributable to the following:

Upstream
increase of $206 million



| |   |                                                
| | - | -----------------------------------------------
| |  | higher realized crude oil prices and production
|
| |  | lower natural gas royalties                    

partially offset by:



| |   |                                
| | - | -------------------------------
| |  | lower prices for natural gas   
|
| |  | higher operating costs and DD&A
|
| |  | higher income taxes            

Midstream
decrease of $95 million



| |   |                                
| | - | -------------------------------
| |  | narrower upgrading differential
|
| |  | lower pipeline throughput      

partially offset by:



| |   |                                               
| | - | ----------------------------------------------
| |  | higher oil and gas commodity marketing income 
|
| |  | higher cogeneration income                    
|
| |  | lower energy related upgrading operating costs
|
| |  | lower income taxes                            

Refined
Products decrease of
$31 million



| |   |                              
| | - | -----------------------------
| |  | lower asphalt product margins

partially offset by:



| |   |                                         
| | - | ----------------------------------------
| |  | improved gasoline and distillate margins
|
| |  | lower income taxes                      

Corporate
increase of $70 million



| |   |                                                                                           
| | - | ------------------------------------------------------------------------------------------
| |  | lower foreign exchange losses on translation of
    U.S. dollar denominated long-term debt

partially offset by:



| |   |                                        
| | - | ---------------------------------------
| |  | higher intersegment profit eliminations

32



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##### 



FORWARD-LOOKING STATEMENTS

Cautionary Statement for the Purposes of
the Safe Harbor Provisions of the Private Securities
Litigation Reform Act of 1995

This document contains certain forward-looking
statements relating, but not limited, to Huskys
operations, anticipated financial performance, business
prospects and strategies and which are based on Huskys
current expectations, estimates, projections and assumptions and
were made by Husky in light of experience and perception of
historical trends. All statements that address expectations or
projections about the future, including statements about
strategy for growth, expected expenditures, commodity prices,
costs, schedules and production volumes, operating or financial
results, are forward-looking statements. Some of Huskys
forward-looking statements may be identified by words like
expects, anticipates, plans,
intends, believes, projects,
could, vision, goal,
objective and similar expressions. Huskys
business is subject to risks and uncertainties, some of which
are similar to other energy companies and some of which are
unique to Husky. Huskys actual results may differ
materially from those expressed or implied by Huskys
forward-looking statements as a result of known and unknown
risks, uncertainties and other factors.

The reader is cautioned not to place undue
reliance on Huskys forward-looking statements. By their
nature, forward-looking statements involve numerous assumptions,
inherent risks and uncertainties, both general and specific,
that contribute to the possibility that the predicted outcomes
will not occur. The risks, uncertainties and other factors, many
of which are beyond Huskys control, that could influence
actual results include, but are not limited to:



| |   |                                                                                                                                                                                                                                                 
| | - | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| |  | fluctuations in commodity prices                                                                                                                                                                                                                
|
| |  | changes in general economic, market and business
    conditions                                                                                                                                                                                 
|
| |  | fluctuations in supply and demand for
    Huskys products                                                                                                                                                                                      
|
| |  | fluctuations in the cost of borrowing                                                                                                                                                                                                           
|
| |  | Huskys use of derivative financial
    instruments to hedge exposure to changes in commodity prices and
    fluctuations in interest rates and foreign currency exchange
    rates                                                             
|
| |  | political and economic developments,
    expropriations, royalty and tax increases, retroactive tax
    claims and changes to import and export regulations and other
    foreign laws and policies in the countries in which Husky
    operates
|
| |  | Huskys ability to receive timely regulatory
    approvals                                                                                                                                                                                      
|
| |  | the integrity and reliability of Huskys
    capital assets                                                                                                                                                                                     
|
| |  | the cumulative impact of other resource
    development projects                                                                                                                                                                                
|
| |  | the accuracy of Huskys oil and gas reserve
    estimates, estimated production levels and Huskys success
    at exploration and development drilling and related activities                                                                   
|
| |  | the maintenance of satisfactory relationships
    with unions, employee associations and joint venturers                                                                                                                                        
|
| |  | competitive actions of other companies, including
    increased competition from other oil and gas companies or from
    companies that provide alternate sources of energy                                                                     
|
| |  | the uncertainties resulting from potential delays
    or changes in plans with respect to exploration or development
    projects or capital expenditures                                                                                       
|
| |  | actions by governmental authorities, including
    changes in environmental and other regulations                                                                                                                                               
|
| |  | the ability and willingness of parties with whom
    Husky has material relationships to fulfil their obligations                                                                                                                               
|
| |  | the occurrence of unexpected events such as
    fires, blowouts, freeze-ups, equipment failures and other
    similar events affecting Husky or other parties whose operations
    or assets directly or indirectly affect Husky                

The reader is cautioned that the foregoing list
of important factors is not exhaustive. Events or circumstances
could cause Huskys actual results to differ materially
from those estimated or projected and expressed in, or implied
by, these forward-looking statements.

33



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##### 



EVALUATION OF DISCLOSURE CONTROLS AND
PROCEDURES

The Companys chief executive officer and
chief financial officer (its principal executive officer and
principal financial officer, respectively) have concluded, based
on their evaluation as of a date within 90 days prior to
the filing of this Annual Report (the evaluation
date), that the Companys disclosure controls and
procedures are effective to ensure that information required to
be disclosed by it in reports filed or submitted by it under the
Securities Exchange Act of 1934, as amended, is recorded,
processed, summarized and reported within the time periods
specified in the Securities and Exchange Commissions rules
and forms, and includes controls and procedures designed to
ensure that information required to be disclosed by it in such
reports is accumulated and communicated to the Companys
management, including its chief executive officer and chief
financial officer, as appropriate to allow timely decisions
regarding required disclosure.

There have been no significant changes to
Huskys internal controls or in other factors that could
significantly affect these controls subsequent to the evaluation
date and the filing date of this Annual Report.

34